Annual or Annual-Transition Report by a Foreign Non-Canadian Issuer — Form 20-F — SEA’34 Filing Table of Contents
Document/ExhibitDescriptionPagesSize 1: 20-F Annual or Annual-Transition Report by a Foreign HTML 6.21M Non-Canadian Issuer
2: EX-2 Plan of Acquisition, Reorganization, Arrangement, HTML 350K
Liquidation or Succession
3: EX-4.7 Instrument Defining the Rights of Security Holders HTML 57K
5: EX-13 Annual or Quarterly Report to Security Holders HTML 60K
12: EX-99.1 Miscellaneous Exhibit HTML 271K
13: EX-99.2 Miscellaneous Exhibit HTML 258K
4: EX-12 Statement re: the Computation of Ratios HTML 65K
6: EX-15.1 Letter re: Unaudited Interim Financial Info HTML 55K
7: EX-15.2 Letter re: Unaudited Interim Financial Info HTML 93K
8: EX-15.3 Letter re: Unaudited Interim Financial Info HTML 55K
9: EX-15.4 Letter re: Unaudited Interim Financial Info HTML 98K
10: EX-15.7 Letter re: Unaudited Interim Financial Info HTML 56K
11: EX-15.8 Letter re: Unaudited Interim Financial Info HTML 56K
20: R1 Cover HTML 230K
21: R2 Group income statement HTML 126K
22: R3 Group statement of comprehensive income HTML 116K
23: R4 Group statement of changes in equity HTML 165K
24: R5 Group balance sheet HTML 185K
25: R6 Group cash flow statement HTML 163K
26: R7 Significant accounting policies, judgements, HTML 282K
estimates and assumptions
27: R8 Non-current assets held for sale (Notes) HTML 78K
28: R9 Business combinations and other significant HTML 59K
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29: R10 Disposals and impairment HTML 151K
30: R11 Segmental analysis HTML 242K
31: R12 Sales and other operating revenues HTML 72K
32: R13 Income statement analysis HTML 83K
33: R14 Exploration for and evaluation of oil and natural HTML 76K
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34: R15 Taxation HTML 166K
35: R16 Dividends HTML 90K
36: R17 Earnings per share HTML 113K
37: R18 Property, plant and equipment HTML 205K
38: R19 Capital commitments HTML 58K
39: R20 Goodwill and impairment review of goodwill HTML 105K
40: R21 Intangible assets HTML 110K
41: R22 Investments in joint ventures (Notes) HTML 103K
42: R23 Investments in associates HTML 192K
43: R24 Other investments HTML 122K
44: R25 Inventories HTML 71K
45: R26 Trade and other receivables HTML 81K
46: R27 Trade and other payables HTML 82K
47: R28 Provisions HTML 101K
48: R29 Pensions and other post-retirement benefits HTML 553K
49: R30 Cash and cash equivalents HTML 65K
50: R31 Finance debt HTML 95K
51: R32 Capital disclosures and net debt HTML 107K
52: R33 Leases HTML 82K
53: R34 Financial instruments and financial risk factors HTML 224K
54: R35 Derivative financial instruments HTML 462K
55: R36 Called-up share capital HTML 556K
56: R37 Capital and reserves HTML 556K
57: R38 Contingent liabilities and legal proceedings HTML 82K
58: R39 Remuneration of senior management and HTML 79K
non-executive directors
59: R40 Employee costs and numbers HTML 553K
60: R41 Auditor?s remuneration HTML 76K
61: R42 Subsidiaries, joint arrangements and associates HTML 93K
62: R43 Condensed consolidating information on certain US HTML 58K
subsidiaries
63: R44 Significant accounting policies, judgements, HTML 340K
estimates and assumptions (Policies)
64: R45 Significant accounting policies, judgements, HTML 231K
estimates and assumptions (Tables)
65: R46 Non-current assets held for sale (Tables) HTML 72K
66: R47 Disposals and impairment (Tables) HTML 143K
67: R48 Segmental analysis (Tables) HTML 234K
68: R49 Sales and other operating revenues (Tables) HTML 69K
69: R50 Income statement analysis (Tables) HTML 83K
70: R51 Exploration for and evaluation of oil and natural HTML 75K
gas resources (Tables)
71: R52 Taxation (Tables) HTML 170K
72: R53 Dividends (Tables) HTML 89K
73: R54 Earnings per share (Tables) HTML 110K
74: R55 Property, plant and equipment (Tables) HTML 209K
75: R56 Goodwill and impairment review of goodwill HTML 96K
(Tables)
76: R57 Intangible assets (Tables) HTML 110K
77: R58 Investments in joint ventures (Tables) HTML 104K
78: R59 Investments in associates (Tables) HTML 187K
79: R60 Other investments (Tables) HTML 68K
80: R61 Inventories (Tables) HTML 69K
81: R62 Trade and other receivables (Tables) HTML 80K
82: R63 Valuation and qualifying accounts (Tables) HTML 85K
83: R64 Trade and other payables (Tables) HTML 80K
84: R65 Provisions (Tables) HTML 96K
85: R66 Pensions and other post-retirement benefits HTML 516K
(Tables)
86: R67 Cash and cash equivalents (Tables) HTML 63K
87: R68 Finance debt (Tables) HTML 95K
88: R69 Capital disclosures and net debt (Tables) HTML 107K
89: R70 Leases (Tables) HTML 82K
90: R71 Financial instruments and financial risk factors HTML 330K
(Tables)
91: R72 Derivative financial instruments (Tables) HTML 463K
92: R73 Called-up share capital (Tables) HTML 111K
93: R74 Capital and reserves (Tables) HTML 492K
94: R75 Remuneration of senior management and HTML 74K
non-executive directors (Tables)
95: R76 Employee costs and numbers (Tables) HTML 89K
96: R77 Auditor?s remuneration (Tables) HTML 72K
97: R78 Subsidiaries, joint arrangements and associates HTML 92K
(Tables)
98: R79 Significant accounting policies, judgements, HTML 66K
estimates and assumptions - Significant judgement:
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(Details)
99: R80 Significant accounting policies, judgements, HTML 65K
estimates and assumptions - Intangible assets
(Details)
100: R81 Significant accounting policies, judgements, HTML 84K
estimates and assumptions - Summary of useful
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101: R82 Significant accounting policies, judgements, HTML 127K
estimates and assumptions - Impairment of
property, plant and equipment, intangible assets,
and goodwill (Details)
102: R83 Significant accounting policies, judgements, HTML 79K
estimates and assumptions - Provisions and
contingencies, decommissioning, environmental
expenditures and liabilities (Details)
103: R84 Significant accounting policies, judgements, HTML 89K
estimates and assumptions - Updates to significant
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104: R85 Non-current assets held for sale - Narrative HTML 108K
(Details)
105: R86 Non-current assets held for sale (Details) HTML 88K
106: R87 Business combinations and other significant HTML 65K
transactions - Business combinations (Details)
107: R88 Disposals and impairment - Schedule of amounts HTML 79K
recognized in the income statement in respect of
disposals and impairments (Details)
108: R89 Disposals and impairment - Schedule of proceeds HTML 71K
and principal gains and losses on disposals by
segment (Details)
109: R90 Disposals and impairment - Narrative (Details) HTML 152K
110: R91 Disposals and impairment - Summary of financial HTML 120K
information relating to the sale of businesses
(Details)
111: R92 Segmental analysis - Narrative (Details) HTML 57K
112: R93 Segmental analysis - Results by Segment (Details) HTML 149K
113: R94 Segmental analysis - Results by Geographical Area HTML 73K
(Details)
114: R95 Sales and other operating revenues (Details) HTML 72K
115: R96 Income statement analysis - Summary of HTML 98K
non-operating income and expense (Details)
116: R97 Exploration for and evaluation of oil and natural HTML 100K
gas resources - Summary of exploration and
evaluation information (Details)
117: R98 Taxation - Disclosure of major components of tax HTML 75K
expense (Details)
118: R99 Taxation - Narrative (Details) HTML 77K
119: R100 Taxation - Disclosure of reconciliation of items HTML 84K
affected by overall tax credit (Details)
120: R101 Taxation - Disclosure of movement in net deferred HTML 72K
tax liability (Details)
121: R102 Taxation - Disclosure of deferred tax in the HTML 124K
income statement and the balance sheet by category
of temporary difference (Details)
122: R103 Taxation - Disclosure of temporary differences, HTML 82K
unused tax credits and unused tax losses (Details)
123: R104 Taxation - Disclosure of unrecognized deferred tax HTML 65K
or write-down of deferred tax assets (Details)
124: R105 Dividends - Narrative (Details) HTML 64K
125: R106 Dividends - Schedule of dividends announced and HTML 85K
paid (Details)
126: R107 Dividends - Schedule of scrip dividends issued HTML 59K
(Details)
127: R108 Earnings per share - Earnings per share, basic and HTML 65K
diluted (Details)
128: R109 Earnings per share - Weighted average number of HTML 75K
shares outstanding reconciliation (Details)
129: R110 Earnings per share - Narrative (Details) HTML 69K
130: R111 Earnings per share - Dilutive effect of share HTML 75K
options (Details)
131: R112 Earnings per share - Dilutive effect of share HTML 75K
units (Details)
132: R113 Property, plant and equipment - Summary of HTML 205K
property, plant and equipment (Details)
133: R114 Capital commitments (Details) HTML 66K
134: R115 Goodwill and impairment review of goodwill - HTML 77K
Disclosure of reconciliation of goodwill (Details)
135: R116 Goodwill and impairment review of goodwill - HTML 79K
Disclosure of goodwill by segment (Details)
136: R117 Goodwill and impairment review of goodwill - HTML 82K
Narrative (Details)
137: R118 Intangible assets - Schedule of intangible assets HTML 110K
(Details)
138: R119 Investments in joint ventures - Summarized HTML 135K
financial information relating to joint ventures
(Details)
139: R120 Investments in joint ventures - Transactions HTML 68K
between group and its joint ventures (Details)
140: R121 Investments in joint ventures - Narrative HTML 73K
(Details)
141: R122 Investments in associates - Summarized aggregate HTML 69K
financial information of associates (Details)
142: R123 Investments in associates - Narrative (Details) HTML 121K
143: R124 Investments in associates - Summarized financial HTML 171K
information relating to associates (Details)
144: R125 Investments in associates - Summary of HTML 67K
transactions between the group and its associates
(Details)
145: R126 Other investments - Schedule of other investments HTML 73K
(Details)
146: R127 Inventories - Schedule of inventories (Details) HTML 76K
147: R128 Inventories - Narrative (Details) HTML 62K
148: R129 Trade and other receivables - Summary of trade and HTML 100K
other receivables (Details)
149: R130 Valuation and qualifying accounts - Schedule of HTML 84K
valuation and qualifying accounts (Details)
150: R131 Trade and other payables - Schedule of trade and HTML 100K
other payables (Details)
151: R132 Trade and other payables - Narrative (Details) HTML 69K
152: R133 Provisions - Schedule of provisions (Details) HTML 109K
153: R134 Provisions - Narrative (Details) HTML 57K
154: R135 Pensions and other post-retirement benefits - HTML 92K
Narrative (Details)
155: R136 Pensions and other post-retirement benefits - HTML 84K
Details of assumptions used to estimate benefit
obligations (Details)
156: R137 Pensions and other post-retirement benefits - HTML 80K
Summary of mortality assumptions (Details)
157: R138 Pensions and other post-retirement benefits - HTML 66K
Current asset allocation (Details)
158: R139 Pensions and other post-retirement benefits - Fair HTML 129K
value of assets held by the defined benefit plans
(Details)
159: R140 Pensions and other post-retirement benefits - HTML 324K
Analysis of the amounts charged to profit (Loss),
Recognized in Other Comprehensive Income, and
Movement in Obligations (Details)
160: R141 Pensions and other post-retirement benefits - HTML 91K
Sensitivity analysis and actuarial assumptions
(Details)
161: R142 Pensions and other post-retirement benefits - HTML 68K
Effect of longevity on expenses and obligations
(Details)
162: R143 Pensions and other post-retirement benefits - HTML 84K
Expected future benefit payments (Details)
163: R144 Cash and cash equivalents - Schedule of cash and HTML 65K
cash equivalents (Details)
164: R145 Cash and cash equivalents - Narrative (Details) HTML 63K
165: R146 Finance debt - Summary of current and non-current HTML 65K
borrowings (Details)
166: R147 Finance debt - Narrative (Details) HTML 74K
167: R148 Finance debt - Summary of weighted average HTML 80K
interest rates (Details)
168: R149 Finance debt - Summary of fair value and carrying HTML 68K
value of borrowings (Details)
169: R150 Capital disclosures and net debt - Disclosure of HTML 82K
the net debt ratio (Details)
170: R151 Capital disclosures and net debt - Disclosure of HTML 120K
reconciliation of liabilities arising from
financing activities (Details)
171: R152 Leases - Narrative (Details) HTML 60K
172: R153 Leases - Disclosure of maturity analysis of HTML 82K
operating lease payments (Details)
173: R154 Leases - Disclosure of quantitative information HTML 67K
about right-of-use assets (Details)
174: R155 Financial instruments and financial risk factors - HTML 115K
Schedule of financial assets and liabilities
(Details)
175: R156 Financial instruments and financial risk factors - HTML 157K
Narrative (Details)
176: R157 Financial instruments and financial risk factors - HTML 72K
Summary of credit risk profile of financial assets
(Details)
177: R158 Financial instruments and financial risk factors - HTML 107K
Financial instruments subject to offsetting,
enforceable master netting arrangements and
similar agreements (Details)
178: R159 Financial instruments and financial risk factors - HTML 122K
Schedule of timing of cash outflows (Details)
179: R160 Financial instruments and financial risk factors - HTML 83K
Schedule of future cash outflows for derivative
instruments (Details)
180: R161 Derivative financial instruments - Summary of fair HTML 109K
value of derivative instruments (Details)
181: R162 Derivative financial instruments - Summary of HTML 132K
maturities of derivative assets and liabilities
(Details)
182: R163 Derivative financial instruments - Analysis of HTML 147K
fair value derivative sssets and liabilities by
maturity and fair value estimation (Details)
183: R164 Derivative financial instruments - Disclosure of HTML 96K
changes in fair value of derivative instruments
(Details)
184: R165 Derivative financial instruments - Narrative HTML 80K
(Details)
185: R166 Derivative financial instruments - Fair value of HTML 79K
hedge ineffectiveness (Details)
186: R167 Derivative financial instruments - Carrying and HTML 77K
notional amounts of hedges (Details)
187: R168 Derivative financial instruments - Weighted HTML 66K
average exchange rates and sales prices, cash flow
hedges (Details)
188: R169 Derivative financial instruments - Summary of HTML 70K
changes in fair value, hedges used to calculate
ineffectiveness (Details)
189: R170 Derivative financial instruments - Summary of HTML 68K
carrying amount of fair value hedges (Details)
190: R171 Derivative financial instruments - Summary of HTML 86K
tenor of nominal amount of hedges (Details)
191: R172 Derivative financial instruments - Weighted HTML 73K
average exchange rates of hedges (Details)
192: R173 Derivative financial instruments - Accumulated HTML 75K
fair value adjustments of the hedged items
(Details)
193: R174 Derivative financial instruments - Movement in HTML 125K
reserves related to hedge accounting (Details)
194: R175 Called-up share capital - Summary of allotted, HTML 103K
called up and fully paid share capital (Details)
195: R176 Called-up share capital - Narrative (Details) HTML 77K
196: R177 Called-up share capital - Treasury shares HTML 76K
(Details)
197: R178 Capital and reserves - Summary of reserves and HTML 303K
other equity interest (Details)
198: R179 Capital and reserves - Narrative (Details) HTML 85K
199: R180 Capital and reserves - Summary of pre-tax tax HTML 124K
amounts of component of other comprehensive income
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200: R181 Contingent liabilities and legal proceedings - HTML 98K
Disclosure of legal proceedings (Details)
201: R182 Remuneration of senior management and HTML 73K
non-executive directors - Remuneration of
directors, senior managment, and non-executive
directors (Details)
202: R183 Remuneration of senior management and HTML 66K
non-executive directors - Narrative (Details)
203: R184 Employee costs and numbers (Details) HTML 99K
204: R185 Auditor?s remuneration - Summary of auditor's HTML 73K
remuneration (Details)
205: R186 Auditor?s remuneration - Narrative (Details) HTML 67K
206: R187 Subsidiaries, joint arrangements and associates - HTML 116K
Disclosures of interests in subsidiaries, joint
arrangements, and associates (Details)
207: R9999 Uncategorized Items - bp-20201231.htm HTML 104K
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Not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission
Securities registered or to be registered pursuant to Section 12(g) of the Act.
None
Securities
for which there is a reporting obligation pursuant to Section i15(d) of the Act.
None
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.
Ordinary Shares of 25c each
i21,415,782,350
Cumulative
First Preference Shares of £1 each
i7,232,838
Cumulative Second Preference Shares of £1 each
i5,473,414
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. iYes☒ No ☐
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Note—Checking
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Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. iYes☒ No ☐
Indicate
by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). iYes☒ No ☐
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18 ☐
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b
p A n n u al R e p o rt an d F o rm 2 0 -F 2 0 2 0 bp Annual Report and Form 20-F 2020 from IOC to IEC
This means we plan to We have set our strategy to transform from an International Oil Company to an Integrated Energy Company focused on delivering solutions for customers. This is a major, necessary step in support of our purpose to reimagine energy for people and our planet, and our ambition to become a net zero company by 2050 or sooner and help the world get to net zero. After more than a century defined by oil and gas through two core businesses, upstream and downstream, we set our strategy to become a very different energy company in the next decade. We remain
committed to delivering long-term value for stakeholders – including shareholders – through a compelling investor proposition. As we reinvent bp, we remain committed to performing while we transform, maintaining our focus on safety, operational excellence and financial discipline. Significantly scale-up our low carbon energy business Focus our oil, gas and refining portfolio Transform our customer mobility and convenience offer Drive down emissions as part of our net zero ambition
01 Strategic report bp Annual Report and Form 20-F 2020 Strategic report Our purpose: reimagining energy 2 Chairman’s letter 4 Chief executive officer’s
letter 6 Energy markets 8 Reinventing bp: Our strategy 15 Our business model 16 Our strategic focus areas 18 Our financial frame and investor proposition 22 Pursuing a strategy that is consistent with the Paris goals 26 Our organizational model 36 Our financial reporting segments 38 Key performance indicators 39 Group performance 42 Sustainability 48 Section 172 statement 63 How we manage risk 64 Risk factors 67 Corporate governance Introduction from the chairman 72 Board of directors 74 Leadership team 78 Board activities 80 Decision making by the board 82 How the board has engaged with shareholders, the workforce and other stakeholders 86 Governance framework 88 Learning, development and induction 90 Board evaluation 91 People and governance committee 92 Audit committee 94 Safety and sustainability committee 100 Geopolitical committee 102 Directors’ remuneration report 103 Remuneration committee 105 Financial statements Consolidated
financial statements of the bp group 129 Notes on the financial statements 160 Supplementary information on oil and natural gas (unaudited) 231 Additional disclosures 301 Shareholder information 331 Glossary 341 Non-GAAP measures reconciliations 348 Signatures 350 Cross-reference to Form 20-F 351 Information about this report 352 Exhibits 352 About bp Through our scale, reach and range of activities we deliver heat, light and mobility products and services to customers around the world, and we plan to do so increasingly, in ways that we believe will help drive the transition to a lower carbon future. We have operations in Europe, North and South America, Australasia, Asia and Africa. Our quick read provides a concise summary of the annual report, highlighting strategy, performance and sustainability information. bp.com/annualreport Our reporting centre brings together all our key reports, including our sustainability report and energy outlook. bp.com/reportingcentre
Glossary Like any industry, ours has its own unique language. For that reason, words and terms marked with « are defined in the glossary. See page 341 2020 in numbers $20.3bn loss for the year attributable to bp shareholders 94% upstream plant reliability« $12.2bn operating cash flow« $72.7bn finance debt 2.4mmboe/d upstream production excluding Rosneft 14.1GW total developed renewables to FID« and renewables pipeline« bp net 9% reduction in estimated emissions fron the carbon in our Upstream oil and gas production« $5.7bn underlying replacement cost loss« 96% refining availability« ˜7% upstream unit production costs« reduction $5.5bn divestment proceeds« $38.9bn net debt« 1,900 strategic convenience sites«
02
bp Annual Report and Form 20-F 2020 Our purpose for people and our planet. Five aims to get bp to net zero Five aims to help the world get to net zero Our ambition is to be a net zero company by 2050 or sooner and to help the world get to net zero. We’ve set out 10 net zero aims, five to help bp get to net zero and five to help the world get there too. We want to help the world reach net zero and improve people’s lives. We will aim to dramatically reduce carbon in our operations and in our production, and grow new low carbon businesses, products and services. We will advocate for fundamental and rapid progress towards the Paris climate goals and aim to be an industry leader in the transparency of our reporting. We know we don’t have all the answers and will listen and work with others. We want to be an energy company with purpose; one that is trusted by society, valued by shareholders and motivating for everyone who works
at bp. We believe we have the experience and expertise, the relationships and the reach, the skill and the will to do this.
03 Strategic report A sustainability frame linking our purpose and Integrating energy systems Partnering with countries, cities and industries Driving digital and innovation Low carbon electricity and energy Convenience and mobility Resilient and focused hydrocarbons Embedding into our DN A Eng aging stakeholders Our values and foundations bp Annual Report and Form 20-F 2020 Our strategy is to become an Integrated Energy Company focused on delivering solutions for customers. We expect to be a very different bp by 2030 by implementing this
strategy. We believe our strategy and financial frame support the delivery of our investor proposition. To deliver our strategy we must operate within a resilient financial frame. Strategic frame Our sustainability frame Financial frame A coherent approach to capital allocation Investor proposition The sustainability frame we set out in September 2020 links our strategy to our purpose – to reimagine energy for people and planet. It focuses on three areas: net zero, people and planet. See page 48 for more information on our sustainability frame. See page 22 for more information on our financial frame. See page 23 for more information on our investor proposition. See page 15 for more information on our strategy. 1 Resilient dividend 2 Strong balance sheet 3 Investing at scale in the energy transition 4 Investing to maximize value in resilient hydrocarbons 5 Share buyback commitment Committed distributions Profitable growth Sustainable
value
04 bp Annual Report and Form 20-F 2020 Chairman’s letter While this is a journey that will require patience, our goal is that bp over time will become a more valuable company for its shareholders and bring wider benefits for society. 7.9% annual dividend yield« ordinary share (2019 6.9%) $6.4bn total dividends distributed to bp shareholders (2019 $8.3bn)
05
Strategic report bp Annual Report and Form 20-F 2020 Dear fellow shareholders, 2020: the year of the pandemic In every sense, 2020 was an extraordinary year. The worst pandemic in a century has cost well over 2 million lives and caused worldwide economic and social disruption. While vaccination programmes are now building momentum, the path to recovery remains uncertain. Because demand for energy is closely linked to human activity, our sector was deeply affected. The combination of a steep fall in share values for almost all oil and gas companies and a new bp distribution policy significantly affected your shareholder returns. As chairman of your board, I am conscious of my responsibilities to bp’s shareholders. When the board decided to reset our distribution policy, it did so with a view to your long-term interests. Our priorities were, and remain, weathering the immediate challenge of the pandemic; paying a resilient dividend; strengthening
our balance sheet; investing into the energy transition; investing in our resilient hydrocarbons business and, after that, returning surplus cash« to shareholders through buybacks. The board was unanimous in its support for this course of action, which will help establish bp as an Integrated Energy Company. I hope that bp’s new investor proposition and financial frame give reasons for optimism about bp’s long-term prospects. As we turn to 2021, the board’s focus is on supporting bp’s leadership team to deliver our new strategy, and on building renewed shareholder confidence through strategic progress and operational and financial performance. 2020 was also tough for our people. My board colleagues and I are proud of them. Their commitment – on rigs, in refineries, across retail stations and everywhere else in bp – helped keep the world’s lights on and allowed us to provide many
emergency services with free or heavily discounted fuel. Despite new COVID-19-related practical challenges, our people maintained the safety of bp’s operations. That is a testament to their careful work. bp’s new purpose 2020 was a remarkable year for bp for other reasons too. With the backing of the board, our new CEO, Bernard Looney, introduced a new company purpose: reimagining energy for people and our planet. That purpose – together with our strong culture and values – underpins the net zero ambition that we set out last year, together with our new strategy, financial frame and investor proposition. It also informed bp’s reinvention – the selection of a new leadership team, and the replacement of bp’s upstream/downstream model with a new, integrated group structure. Change of this scale necessitated a reorganization of how we work. That reorganization will ultimately see close
to 10,000 colleagues leaving bp. Saying goodbye has been difficult, but the result is a leaner, flatter, nimbler company – better able to realize the opportunities of the energy transition. Macro-economic developments have only strengthened the board’s belief that the direction in which we are taking bp is the right one – including China’s new net zero target, the EU’s Green Deal, the UK’s plan for a green industrial revolution, and the US’s recommitment to the Paris Agreement. Today, global energy markets are even further down the path of fundamental change – and bp is well-positioned to help to speed the world’s journey to net zero. A year of engagement While this is a journey that will require patience, our goal is that bp over time will become a more valuable company for its shareholders and bring wider benefits for society. Of course, the journey to net zero
is, in part, one of discovery. For that reason, the board and bp’s leadership team know that we must be fully open to advice, learning and challenge. 2020 was therefore a year of engagement with our stakeholders, and I am grateful for the inputs we received – which helped us shape our new strategy, financial frame and investor proposition, sustainability frame and position on biodiversity. We will keep listening, and we count on you to share your feedback with us as we travel the road to net zero together. Evolution of the board As the company evolves, the board’s composition will evolve too – reflecting the need for new experiences and skills aligned with bp’s new direction. During the year, the board said goodbye to our former CEO, Bob Dudley, and to Brian Gilvary, our former CFO. Sir Ian Davis, Nils Andersen and Dame
Alison Carnwath have also stepped down from the board, and we shall shortly say farewell to Brendan Nelson. Collectively and individually they served with distinction – bp is very fortunate to have had their wise advice and strong leadership. We are just as fortunate to welcome Tushar Morzaria, Karen Richardson and Johannes Teyssen to bp’s board for the first time. Closing thanks I would like to thank Bernard Looney, his leadership team and everyone in bp for their work during 2020. Throughout this challenging year, they showed characteristic determination. Finally, I thank you, our shareholders. I am grateful both for the continued support we received during 2020, and also for the support of our new shareholders. During 2020, we received investment and other endorsement from those who told us they would not have considered supporting bp were it not for the transformation we have begun. We look forward to repaying the faith you
have placed in bp. Helge Lund, Chairman 22 March 2021
06 bp Annual Report and Form 20-F 2020 Chief executive officer’s letter $20.3bn loss attributable to bp shareholders Dear shareholders, The year 2020 will be remembered above all for the pain, sadness and loss of life caused by COVID-19. At bp, our thoughts are with the families and loved ones of the colleagues we have lost. Thousands more on our teams have had the virus, and life under lockdown has meant additional challenges, and anxiety for everyone. I want to pay particular tribute to those on the frontline of our business who have kept our plants and platforms running, our shops and forecourts open,
and energy flowing to the world. They have sacrificed so much and earned our deepest respect and appreciation. Responding to brutal conditions We began our transformation from an International Oil Company to an Integrated Energy Company against this backdrop, along with lower oil and gas prices, lower refining margins and unprecedented falls in demand for our retail and aviation fuels. Our response included lowering costs, strengthening the balance sheet with an innovative hybrid bond issue, and advancing our strategy to become I want to pay particular tribute to those on the frontline of our business who have kept our plants and platforms running, our shops and forecourts open, and energy flowing to the world.
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Strategic report bp Annual Report and Form 20-F 2020 a more diversified, resilient and lower carbon company. As part of our strategy planning process, we reviewed our portfolio and development plans. This work – informed by bp’s views of the long-term price environment – led to significant impairment charges and non-cash exploration write-offs in the second quarter. For shareholders, all this was reflected in a reset dividend and a diminished share price. I recognize the financial impact this must have had on you. However, I wholeheartedly believe we will not just restore, but will enhance the long-term sustainable value of your company through the actions we are taking to reinvent bp. And despite the most brutal operating conditions I can remember in almost 30 years in this industry, we have made considerable operational and strategic progress. Performing while transforming The loss of $20.3 billion we reported for the year
is clearly disappointing. However, it in no way reflects the heroic efforts of the bp team in extremely difficult circumstances, or their deep commitment to performing while transforming: Most importantly – our safety performance continued to improve. Reliability of 94% for bp’s operated plants« and refining availability« of 96% represents remarkably strong performance, especially given the challenges faced by our frontline staff. Capital was reset and we delivered at the lower end of the range. We made good progress towards our net debt« target, including the contribution from high grading our portfolio and $6.6 billion of divestment and other proceeds received during the year. New oil and gas production came on from four major projects« – in India, Oman, the UK and the US. Natural gas from the Shah Deniz field in the Caspian Sea arrived in Italy following final completion of
the historic Southern Gas Corridor project. And we doubled our retail network in growth markets to around 2,700 retail sites«, plus the addition of around 300 strategic convenience sites«. Reinventing bp This performance is even more remarkable given that we have been carrying out the most extensive reorganization in bp’s 112-year history. We have retired the upstream/downstream business model that has served bp very well. In its place we have introduced a leaner, flatter structure, stripping away tiers of management and lowering the workforce towards a target of around 10,000 fewer jobs. My role is now five layers at most away from more than half of our employees. That means people’s ideas and voices can be more easily heard – and decisions taken much faster. We are now more centralized, more agile, and better integrated. This enables us to maximize value creation in a rapidly evolving market through economies
of scale, and by exploiting synergies and driving continuous improvement in operational performance. We are now organized around four business groups. Production & operations is the operating heart of the company – and is focusing our resilient hydrocarbons portfolio on value. Customers & products is growing our convenience and mobility offers for an increasing number of customers. Gas & low carbon energy is growing to help meet rapidly increasing clean energy demand. Innovation & engineering acts as a catalyst, opening up new and disruptive business models and driving our digital transformation. And our trading & shipping business and regions, cities & solutions team knit together the offers of our four core groups to drive greater value creation. Reimagining energy Completing our transformation to a net zero Integrated
Energy Company will take time. But we are led by our purpose – to reimagine energy for people and our planet – and motivated by the opportunity we see in the energy transition. Trillions of dollars of investment will be needed over the next 30 years in replumbing and rewiring the global energy system. We now have offshore wind partnerships in the US with Equinor and in the UK with EnBW – two of the best regions globally for the world’s fastest-growing source of energy. Our solar development joint venture«, Lightsource bp, is growing prolifically. We are working with Ørsted to develop green hydrogen for our Lingen refinery. We have joined forces with the mobility platform DiDi to build a network of electric vehicle chargers in China, by far the world’s biggest market for EVs. And we have a growing list of low carbon partnerships with cities such as Aberdeen and Houston and some of
the world’s leading companies, including Amazon, Microsoft, Qantas and Uber. A compelling investor proposition We are fully focused at all times on the bottom line of the business – on executing our strategy while operating safely, reliably and with discipline. We continue to build resilience and strength in the balance sheet as conditions remain challenging and uncertain while vaccines roll out, the pandemic recedes, and economies look to recover. At the same time, we are transforming to create value from the energy transition over the long term. We see tremendous business opportunity in providing people with the reliable, affordable, clean energy they want and need. Our net zero ambition is clearly the right thing for society, but we know it does not give us a free pass in a fast-changing world. We have to show you the evidence that we can compete fiercely and add value – in service of the compelling investor proposition
we believe we offer: Committed distributions – including the dividend as the number one priority; Profitable growth; and Sustainable value. This is all in service of growing long-term shareholder value, that is our job. And I promise to keep you well informed as we execute our plans. As ever, thank you for your continued support – I will never take that for granted. And I look forward to any feedback you might have. Thank you. Bernard Looney, Chief executive officer 22 March 2021
08 bp Annual Report and Form 20-F 2020 Energy markets Global context Mobilizing safely in the North Sea In 2020 bp managed more than 15,000 journeys by people mobilizing
to and from our North Sea assets. As the COVID-19 pandemic took hold in the UK, the bp North Sea team quickly implemented wide-ranging and robust COVID-19-specific measures to protect the safety and wellbeing of offshore colleagues. The ‘Safe Passage’ programme was introduced during the first UK lockdown to help individuals travel to Aberdeen for mobilization as safely as possible. The programme provided door-to-door transport, accommodation during the journey to Aberdeen and hotels in the city dedicated to bp staff and contractors. We introduced pre-mobilization COVID-19 testing in Aberdeen, one of the first operators in the North Sea to do this. Social distancing and enhanced hygiene and cleaning regimes continue to play a vital role in protecting the health and wellbeing of our offshore teams. Specialist ‘C-MED’ medevac helicopters, equipped with an on-board medic and configured to enable social distancing, were
introduced to safely transport individuals suspected of contracting the virus back to shore for further treatment and support. COVID-19 The COVID-19 pandemic has affected individuals, countries and businesses. The spread of the pandemic quickly plunged the world economy into recession and reshaped social norms and attitudes. Globally, businesses have had to change established assumptions and introduce new models and ways of working. For bp, it has had an adverse impact on our business, including on the demand for our products and on their prices. But the more we understand about the consequences for the global economy – and the inevitable uncertainty it brings – the more convinced we are that our ambition and strategy are taking us in the right direction for bp, for our employees, our shareholders and society. Impact on the economy The global economy is estimated to have contracted 4.3% in 2020, the steepest decline in economic
activity since 1946, caused by COVID-19. In advanced economies the recovery from the initial contraction was dampened by resurgences of COVID-19 cases, leading to an annual contraction of 5.4%. Most emerging markets, excluding China, also experienced deep recessions, with growth of -5% in 2020, while in China the economy grew by 2%a. a World Bank Global Economic Prospects, January 2021. Our response As COVID-19 continues to affect communities around the world, we have focused our effort on three priorities. 1 Protecting our people. 2 Supporting communities where we live and work. 3 Strengthening our finances. Our leadership teams were in daily discussions to respond to the conditions in the countries where we operate as the pandemic unfolded. We had a three-tier response model with executive-level, business, country and incident management steering committees. Some examples are given on the next page. The business environment is fundamentally changing.
The world is on an unsustainable path and its carbon budget is running out. Energy markets have begun a process of significant, lasting change in response to this – shifting increasingly towards low carbon and renewables. And in 2020 we saw further changes, as COVID-19 spread across the globe.
09 Strategic report bp Annual Report and Form 20-F 2020 In 2020 we set a new target of $25 billion of proceeds between the second half of 2020 and 2025, of which we’ve completed or agreed transactions for over half of this target. This includes the agreed sale of a 20% interest in Oman’s Block 61 and proceeds from the divestments of our petrochemicals
business and Alaska interests. We have a deep hopper of potential future divestment options. As we execute this programme, we will continue to be focused on value. Capital expenditure Capital expenditure« for 2020 was $14 billion, around 28% lower than 2019. Organic capital expenditure« for 2020 was $12 billion, in line with the guidance given in April. Liquidity Finance debt was $72.7 billion and net debt« was $38.9 billion at the end of 2020. We are actively managing the profile of our debt portfolio. We issued perpetual hybrid bonds with a US dollar equivalent value of $11.9 billion in June 2020, and we bought back an aggregate US dollar equivalent value of $8 billion of debt in the third quarter of 2020, January 2021 and March 2021. bp had around $44 billion of liquidity, consisting of cash and cash equivalents (net of restricted cash) plus undrawn revolving credit facilities committed credit and bank facilities,
at the end of 2020. In April 2020 Moody’s reaffirmed BP p.l.c.’s A1 credit rating and revised its outlook from stable to negative. The short-term P-1 rating was also reaffirmed. In January 2021 S&P revised its outlook on BP p.l.c. from stable to negative and affirmed BP p.l.c.’s long- and short-term corporate credit rating of A-/A-2. From January 2021, Fitch Ratings has provided a solicited long-term corporate credit rating to BP p.l.c. of A with stable outlook. In February 2021, Fitch Ratings assigned BP p.l.c. a short-term corporate credit rating of F1. bp’s financial performance, including cash flows and net debt, has been and will continue to be impacted by the extent and duration of the current market conditions and the effectiveness of the actions that it and others take, including its financial interventions. It is difficult to predict when current supply and demand imbalances will be resolved
and what the ultimate impact of COVID-19 will be. See page 22 for more information on capital allocation. We have addressed our response to COVID-19 in further detail throughout this report: See page 63 Our stakeholders. See page 64 How we manage risk. See page 67 Risk factors. See page 87 Workforce engagement. 1 Protecting our people Our first priority is the safety and health of our people. Our people involved in, or supporting, critical operations continued at their normal workplace during the pandemic and we put additional processes in place to help protect them. These included operating robust protocols for health and pre-mobilization checks, PPE, travel and workplace access, social distancing and isolation. Employees who were able to work from home were asked not to come into their workplace and we put business travel restrictions in place. Many office-based workers continue to work from home at the time of publication and are likely to do
so for the foreseeable future as ways of working change. We liaised closely with industry peers and other organizations to regularly test our approach on specific safety issues. And we created a global COVID-19 OneMap, providing our businesses with current local COVID-19 risk profiles including rates of infection, vaccines rates and procurement. 2 Supporting communities Providing essential support for the communities where our people live and our businesses operate was a priority throughout our response to COVID-19. We offered support to governments and partners, using our expertise and resources to support the relief effort. The bp Foundation donated $2 million to the World Health Organization’s COVID-19 Solidarity Response Fund, which supports medical professionals and patients worldwide by providing critical aid and supplies. The fund also helps track and understand the spread of COVID-19 and supports efforts to develop tests, treatments
and vaccines. 3 Strengthening our finances The economic consequences of COVID-19 for the world remain uncertain at the time of publication. In response to this uncertainty, we took deliberate steps to strengthen our finances – reinforcing liquidity, rapidly reducing spending and costs, driving our cash balance point lower. Divestment programme We delivered our plans for $15 billion of announced divestments, which commenced at the start of 2019, in June 2020 – a year earlier than expected. In 2020 we supplied more than 10 million litres of free fuel to emergency service vehicles across the UK. We ran programmes during 2020 and 2021 offering free fuel to UK emergency vehicles – including police, fire, blood transportation, emergency NHS ambulances and NHS Trust non-emergency vehicles. Under the programmes, emergency services vehicles issued with either a bp Plus or Allstar fuel card could fill up without charge at bp’s
network of 1,200 retail sites across the UK, including charging of electric vehicles through bp pulse. Supplying free fuel for emergency services vehicles
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Strategic report CO2 emissions from energy use Gt of CO2 20502020 2030 20402010200019901980 -5 40 IPCC 2 Median History Rapid Net Zero Business-as-usual IPCC 1.5 Median 0 5 10 15 20 25 30 35 Well below 2ºC 1.5ºC bp Annual Report and Form 20-F 2020 Our bp Energy Outlook considers three main scenarios that explore the possible pathways the energy transition may take over the next 30 years. The uncertainty is substantial and these scenarios are not predictions of what is likely to happen or what bp would like to happen. Rather they explore the possible implications of different judgements and assumptions concerning the nature of the energy transition. a For more information on Paris-consistent pathways, see page 26. b The Intergovernmental Panel on Climate Change (IPCC) is the United Nations’ body for assessing the science related to climate change. It is the leading source of data that summarizes the potential pathways to achieve the
Paris goals. The IPCC compiles a database of the published results on mitigation pathways from modelling teams around the world. c Ranges show 10th and 90th percentiles of IPCC scenarios. See bp Energy Outlook 2020 for more information. This chart compares the three main scenarios from the bp Energy Outlook 2020: Rapid, Net Zero and Business-as-usual, with the range of scenarios included in the Intergovernmental Panel on Climate Changeb, which were judged to be consistent with meeting the Paris climate goalsc. Scenarios for strategic decision making We have been using scenarios at bp to inform strategy, manage risk and improve decision making for many years. The scenarios we used to inform our new ambition and strategy were based on a collaborative approach between our economists, strategists and our senior management team. Three scenarios to explore the energy transition Rapid One of many possible scenarios that can be considered ‘consistent
with Paris’, in line with a ‘well below 2 degrees’ pathwaya. In this scenario emissions from energy use fall by around 70%, with a fall of approximately 80% in the developed world and 65% in the emerging world. Net Zero In which global energy systems emissions fall by 95% by 2050 versus 2018, in line with a ‘1.5 degrees’ pathwaya. Changes in societal actions and behaviours are a key driver in this scenario. Business-as-usual A continuation of recent trends without major change in the pace or direction of policy tightening; this scenario is not ‘consistent with Paris’ and results in a reduction in global energy greenhouse gas emissions of only 10% by 2050 versus 2018. Our Energy Outlook
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bp Annual Report and Form 20-F 2020 Some scenarios start from today and project forward over a timeframe in which the current structure of the energy system helps to inform the pace and nature of the transition path. Other scenarios start in the distant future, breaking free from the inherent inertia in the energy system (and potentially our thinking), and look back to the present from that new perspective. In thinking about appropriate scenarios to inform our new strategy, we used both approaches. The scenarios chosen to explore the range of uncertainty surrounding the future of the global energy system span a broad range of energy transition paths. Importantly, the scenarios are not predictions of what is likely to happen or what bp would like to happen. Rather they consider the possible implications of different judgements and assumptions and so help to design a strategy which is resilient to the wide range of uncertainty we face. By considering
various time horizons, we can identify key milestones or signposts which might emerge over the next five, 10 or 30 years and inform our view of the key sources of uncertainty affecting the global energy system. We actively monitor for changes in the external environment, and refresh or review our scenarios as needed in response to these signals. How we create scenarios We quantify these scenarios in the bp Energy Outlook 2020 using our global energy modelling system. This comprises of a suite of models developed over the past 10 years to help us understand supply and demand dynamics of the global energy system. The modelling framework uses historical data based on the bp Statistical Review of World Energy, IEA energy balances and a range of other energy and non-energy data sets. The model combines supply, end-use demand, and production in intermediate sectors, including power and hydrogen, to create global energy outlooks. Each scenario is determined
by a set of key assumptions including population and economic growth, pace of technological change, resource constraints and government policies. Prices are used to balance supply and demand. The modelling techniques used vary by sector and include a combination of econometric modelling, least-cost optimization, adoption curves and consumer choice modelling. The regional coverage varies by sector but at its most aggregated the model produces views for 14 regions, across six sectors, more than 20 energy and technology sources and associated CO2 emissions from each. It produces annual data out to 2050. Scenarios are generated based on our own judgements alongside views from external organizations. For example, population growth from the United Nations, economic growth supported by views from Oxford Economics, resource availability based on Rystad Energy’s global upstream database, power modelling informed by Aurora Energy Research and global system
dynamics based on a proprietary TIMES integrated assessment model. All scenarios typically take into account historical evidence, current policies, user judgement and specialist projections. In developing the scenarios, we benchmark our views against scenarios from external organizations including from the Intergovernmental Panel on Climate Change’s (IPPC) 2019 Special Report on Global Warming of 1.5°C, IEA’s World Energy Outlook 2020 and IHS Markit’s Energy and Climate Scenarios. How scenarios inform our strategy The scenarios described in the bp Energy Outlook 2020 helped inform bp’s strategy process, alongside a wide range of other analyses and information. As we developed the strategy, the scenarios were reviewed and refined to ensure they remained relevant, for example, they were completely refreshed to account for the possible implications of COVID-19, and they remained challenging for example,
by including a scenario in which global emissions from energy reach near zero by 2050. The aim of the scenarios is to aid our understanding of how the pace and nature of the energy transition may affect the global energy system and so help our strategy be robust and resilient to the range of uncertainty we face. Given that, we believe that it is neither useful nor sensible to try to identify one scenario as being more or less likely than another. Energy markets continued In the bp Energy Outlook 2020, COVID-19 is assumed to have a persistent impact on economic activity and energy demand.
13 Strategic report Shares of primary energy 2040 2045 20502035203020252018
0% 20% 40% 60% 80% 100% Rapid Net Zero Business-as-usual Shares of primary energy 2040 2045 20502035203020252018 0% 20% 40% 60% 80% 100% Rapid Net Zero Business-as-usual Shares of total final comsumption 2040 2045 20502035203020252018 0% 20% 40% 60% 80% 100% Rapid Net Zero Business-as-usual Share of primary energy in Rapid 2035 2050202020051960 1975 19901945193019151900 0% 20% 40% 60% 80% 100% Other non-fossil fuelsOil Coal Natural gas Renewables bp Annual Report and Form 20-F 2020 World continues to electrify The rapid growth in renewables is supported by the increasing role of electricity in total final energy consumption in the three scenarios. Importance of fossil fuels declines The share of fossil fuels in global primary energy falls from around 85% in 2018 to between 65% and 20% by 2050 in the three scenarios. Rapid growth in renewable energy Increases in renewable energy dominate growth in primary energy, with its share increasing from 5% in 2018 to between
20% and 60% by 2050 in the three scenarios. Global energy demand across the scenarios Although the three energy outlook scenarios differ in many respects, some trends are common across them and across the wide range of other analyses and information we refer to. Global energy demand continues to grow, at least for a period, driven by increasing prosperity and living standards in the emerging world, and there are three common trends in how the structure of energy demand changes over time. In addition to the changing structure of energy demand, the scenarios also highlight how global markets may change if and when there is a transition to a lower carbon energy system, with a more diverse energy mix, greater consumer choice, more localized energy markets, and increasing levels of integration and competition. Changing structure of the global energy system
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bp Annual Report and Form 20-F 2020 Our beliefs on the energy transition Energy markets continued Three features are common across our Energy Outlook scenarios and they form a set of three core beliefs as to how energy demand is likely to change over the next three decades. And those core beliefs lead to three more about how the energy system will have to change in response to evolving demand, out to 2050. These core beliefs underpin our new strategy. bp.com/energyoutlook The world will electrify, with renewables a clear winner Customers will redefine convenience and mobility, driven by electrification, digital and fleets Oil and gas challenged but will remain part of the energy mix for decades Digital will continue to transform our lives – creating opportunities to drive innovation, unlock value and engage new customers and markets Customers – countries, cities, industries and corporates – will demand bespoke energy solutions
Energy systems will become increasingly multi-technology, integrated and local
15 Strategic report A sustainability frame linking our purpose and Integrating energy systems Partnering with countries, cities and industries Driving digital and innovation Low carbon electricity and energy Convenience and mobility Resilient and focused hydrocarbons bp Annual Report and Form 20-F 2020 From IOC to IEC We began 2020 operating under our previous strategy, announced in 2017, which focused on four strategic priorities: Growing advantaged oil and gas in the Upstream. Market-led growth in the Downstream. Venturing and low carbon across multiple fronts. Modernizing the whole
group. In February 2020, we announced our new ambition to be a net zero company by 2050 or sooner and to help the world get to net zero. And in August we announced a new strategy to get us there, which builds on the foundations we’ve developed since 2017. See page 48 for more about our sustainability frame. Our strategy is underpinned by our ew s stain bility frame and by advocating for policies that support net zero. Our strategy Focuses on three areas of activity: low carbon electricity and energy, convenience and mobility, and resilient and focused hydrocarbons. Each focus area represents an attractive opportunity in its own right. Taken individually, they are not unique to bp. But we plan to leverage three sources of differentiation to help us amplify value: integrating energy systems, partnering with countries, cities and industries, and driving digital and innovation. An Integrated Energy Company delivering solutions for customers. By
following this strategy, we expect bp to be a very different energy company by 2030. Reinventing bp: our strategy
16 bp Annual Report and Form 20-F 2020 Reinventing bp – our business model Business model inputs Skills in the world of energy, built up over more than 110 years. Understanding of energy markets and how they move. Thousands of expert scientists, engineers and technologists. People with outstanding capabilities in trading, shipping, marketing and innovation. Strong relationships with leading companies, universities and governments. Thriving energy transition, convenience and mobility partnerships and businesses that we are growing all over
the world. A resilient financial frame and a disciplined approach to capital allocation. Strategic activities How we aim to create value Safety is our core value. It underpins our business model and permeates everything we do. Convenience and mobility Our customers & products business group is an integral part of our growth and returns strategy. We aim to put customers at the heart of everything we do. Low carbon electricity and energy Through our gas & low carbon energy business, we aim to grow scale. Our low carbon businesses are complemented by integrated gas, which has an important role in the energy transition. Expanding and scaling our differentiated fuels and lubricants offers in growth markets (see page 24), aiming to help shape these markets over time to lean into the transition to low carbon mobility. Redefining convenience through partnerships with some of the world’s leading brands and continuing to develop
innovative offers, making buying our retail goods and fuels even more convenient for customers. Developing next-gen mobility solutions, including electrification, sustainable fuels and hydrogen. Growing our renewables portfolio, including offshore wind and solar. Building an integrated low carbon electricity position in select developed and emerging markets. Growing our integrated gas position, building on our high-value equity upstream gas, our LNG portfolio« and our marketing capability. Scaling our bioenergy business, focusing on biofuels, biogas and biopower. Accelerating to take early positions in hydrogen and carbon capture, use and storage. Delivering value for bp, our shareholders and society See page 59 for our safety performance in 2020.
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Strategic report bp Annual Report and Form 20-F 2020 Sources of differentiation Resilient and focused hydrocarbons Through our production & operations business, we aim to produce the affordable hydrocarbon energy and products the world needs, and generate cash to fund our operations and our transformation to an Integrated Energy Company. Integrating energy systems We are focused on driving integration in everything we do. Through integration we bring everything together, to create end-to-end solutions for our customers. Partnering with countries, cities and industries By leveraging relationships and building new partnerships we aim to provide integrated energy and mobility solutions to help cities and industries reduce carbon emissions while creating exciting business opportunities. Driving digital and innovation We innovate with a strong focus on digital to drive operational efficiencies, enable our workforce and engage better with our
customers. This includes building new businesses through bp ventures and Launchpad. Always putting safety first. Aiming to eliminate life-changing injuries and the most serious process safety events. Reducing emissions, aligned with our aims, while delivering the energy the world needs. Transforming operations and improving efficiency. Maintaining a resilient portfolio through investment efficiency and high grading. Flexibly deploying talent to our most valuable opportunities and to solve our biggest issues. 214TWh traded electricity in 2020 10-15 city partners aim by 2030 38 bp ventures and Launchpad businesses in total Reinventing our business model As we transition from an International Oil Company to an Integrated Energy Company, we are reinventing our old business model, which comprised three main activities: Finding and generating energy. Refining, manufacturing and marketing. Delivering products and services. Our new business
model is more integrated and faces the energy transition head on. We believe it can deliver for the changing demands of stakeholders, with an absolute focus on operational excellence, so that our businesses are safe, reliable and efficient. Delivering value for our stakeholders Employees Investors Society Suppliers and partners Customers Governments and regulators for people and our planet. By delivering value to our stakeholders we can achieve our purpose. See page 36 for details of our organizational model.
18 bp Annual Report and Form 20-F 2020 Reinventing bp – our strategic focus areas In order to advance our purpose and ambition, we have identified
three strategic focus areas, and we’ve set targets and aims against these out to 2025 and 2030. These provide the basis for a common set of enduring objectives for bp as we transform the organization consistent with the long-term energy transition. Some examples of how we performed in 2020 are also set out here. As we deliver our strategy, we will focus on maximizing value through operational and commercial excellence, see pages 36-38 for more information. Strategic focus areas We aim to grow our renewables and bioenergy businesses, seek early positions in hydrogen and carbon capture utilization and storage and strengthen our gas position. These activities form an integrated low carbon portfolio that will help transform bp as we transition from an International Oil Company to an Integrated Energy Company. See page 20 for an example of our strategy in action. Metrics Developed renewables to final investment decision« Bioenergy production«	
LNG portfolio« Traded electricity« We will continue to focus on customers and respond to their changing needs. We aim to redefine convenience and scale up our differentiated offers in growth markets and next-gen mobility solutions, including electrification, sustainable fuels and hydrogen. See page 24 for an example of our strategy in action. Customer touchpoints« Strategic convenience sitesb« Retail sites in growth marketsb« Castrol sales and other operating revenues« Electric vehicle charge pointsa« Margin share from convenience and electrificationb« Our hydrocarbons business is essential to our transformation to an Integrated Energy Company. The cash flow from our oil, gas and refining activities enable our strategy, allowing us to invest in the energy transition and support our two growth areas – low carbon electricity and energy, and convenience and mobility. See
page 34 for an example of our strategy in action. Unit production costs« Upstream productionc Upstream plant reliability« Refining throughput Refining availability«
96% <1.5mmb/d 19 Strategic report bp Annual Report and Form 20-F 2020 2030 Performing while transforming2025 50Kb/d 25Mtpa 350TWh >100Kb/d 30Mtpa 500TWh 2020 3.3GW 2019 2.6GW 30Kb/d 2019 23Kb/d 20Mtpa 2019 15Mtpa 214TWh 2019 250TWh 20GW 50GW bp and Equinor strategic US offshore wind partnership, see page 20. Partnered with Microsoft to progress our respective sustainability aims, including plans to supply Microsoft with renewable energy and extend its cloud-based
services within bp. Lightsource bp, in which we have a 50% share, has more than doubled its global presence from five to 14 countries and grown its development pipeline from 1.6GW to 17GW, since joining with bp in 2016. Formed the Northern Endurance Partnership, with five energy companies, to develop the offshore infrastructure to transport and store millions of tonnes of carbon dioxide emissions safely in the UK North Sea. Partnered with Ørsted and plan to develop an industrial-scale project to produce hydrogen from water, powered by wind. Joined with Aberdeen City Council to help achieve its net zero vision to reduce carbon emissions and become a climate-positive city. Agreed to extend our relationship with Amazon, to supply additional renewable energy to power its operations, and Amazon Web Services, enabling the acceleration of bp’s programme to digitize its infrastructure and operations. >15 million >20 million >2,300
>3,000 7,000 >8,000 ~$7.5bn >$8bn >25,000 >70,000 ~35% ~50% More than doubled retail sites in growth markets to 2,700. Added ~300 strategic convenience sites across our retail network, bringing the total to 1,900. Announced the start of our new mobility joint venture« in India with Reliance, Jio-bp, see page 24. Increased the number of electric vehicle charge points to 10,100 and began the rollout of ultrafast charging points across the UK and Germany. Rolled out 1,400 electric vehicle charge points as part of our joint venture with DiDi in China. Increased margin share from convenience and electrification to 27.6%. 11.5 million 2019 >10 million 1,900 2019 1,600 2,700 2019 1,300 $5.4bn 2019 >$6.5bn 10,100 2019 >7,500 27.6% 2019 ~25% ~$6/boe ~2mmboe/d ~1.5mmboe/d >96% ~1.2mmb/d 96% >96% We’re on track to deliver on our growth target since 2016 of 900mboe/d from new
major projects« by the end of 2021, with 700mboe/d of production capacity on line by the end of 2020. And we started up four major projects: Atlantis in the Gulf of Mexico, see page 34, Ghazeer in Oman, Vorlich in the North Sea, and KG D6 R Cluster in India. Completed the Southern Gas Corridor pipeline system, with the Trans Adriatic pipeline beginning gas deliveries. Tested the green completions concept on our Ghazeer wells, sending hydrocarbons to a production facility instead of flaring them. Sold our petrochemicals business to INEOS. Ceased fuel production at our Kwinana refinery to convert it into an import terminal. Agreed to sell a 20% interest in Oman’s Block 61. $6.39/boe 2019 $6.84/boe 2.4mmboe/d 2019 2.6mmboe/d 94% 2019 94.4% 1.6mmb/d 2019 1.7mmb/d 96% 2019 94.9% c Relative to 2019, we expect our hydrocarbon production to be around 40% lower by 2030 reflecting active management and high-grading of the portfolio, including divestment
of non-core assets. We will not undertake exploration activity in new countries. a Reported to the nearest 100. b The nearest GAAP measures of the numerator and denominator are RC profit before interest and tax for Downstream. A reconciliation to GAAP information is provided on page 318.
20 bp Annual Report and Form 20-F 2020 Reinventing bp – our strategy in action
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Strategic report bp Annual Report and Form 20-F 2020 Low carbon electricity and energy We’re teaming up with Equinor to form a new strategic partnership to develop offshore wind projects in the US. We believe we can achieve more together, working to become leaders in the fastest-growing renewables sector and helping the world get to net zero. What we’re doing The partnership includes development of four assets in two existing offshore wind leases on the US East Coast. And we expect to pursue further opportunities for offshore wind in the US. We’re investing $1.1 billion for a 50% share in two leases: Empire Wind and Beacon Wind. Empire Wind, NY, is expected to have 2GW generating capacity, once operational. Beacon Wind, MA, is expected to have 2.4GW generating capacity, once operational. In January 2021, the Empire Wind 2 and Beacon Wind 1 projects were selected to provide New York State with 2.5GW of power –
the biggest US offshore wind award to date – adding to the existing commitment to supply 0.8GW. Why it matters Our strategy aims to increase our annual low carbon investment tenfold by 2030 and rapidly grow our developed renewable generating capacity. The partnership will leverage bp’s trading expertise and onshore wind experience with Equinor’s sector-leading track record in offshore wind, and is expected to deliver value for our shareholders and help the world transition to low carbon energy. Why offshore wind? Offshore wind is growing at around 20% a year globally and is recognized as a core part of reducing global emissions. This was bp’s first ever offshore wind venture and marks an important step in the delivery of our strategy to rapidly grow our renewable electricity and energy portfolio. Building on this progress in 2021, bp and Energie Baden-Wuerttemberg AG (EnBW) were selected as the preferred bidder
for two major leases in the UK Offshore Wind Round 4, marking our entry into the largest offshore wind power sector in the world. 2 million Together, these assets have the potential to generate power for more than 2 million US homes. Our partnership with Equinor will play a vital role in allowing us to deliver our aim of rapidly scaling up our renewable energy capacity, and in doing so help deliver the energy the world wants and needs. Dev Sanyal EVP, gas & low carbon energy See pages 24 and 34 for more examples of our strategy in action.
22 bp Annual Report and Form 20-F 2020 Reinventing bp – our financial frame and investor proposition
Our new financial frame aims to provide a stable foundation for bp, strengthening our balance sheet, and providing a clear approach to capital allocation. And through our disciplined approach to investment, we expect to create the opportunity to significantly increase our investment in low carbon activities in this decade, while also operating a high-quality base business. A coherent approach to capital allocation A clear set of priorities Resilient dividend: We aim to fund a resilient dividend intended to remain fixed at 5.25 cents per ordinary share, per quarter, subject to the board’s discretion. Strong balance sheet: In the near term, we target deleveraging to $35 billion of net debt« and maintaining a strong investment grade credit rating thereafter. Investing at scale in the energy transition: We plan to allocate sufficient capital to advance our energy transition strategy, with this allocation intended to rise once our near-term
deleveraging target is achieved. We have a range of sector-specific internal rate of return hurdles for transition and low carbon investments between 10% and 15%. For renewable power, we look for returns of at least 8% to 10% levered. All of this is then optimized to make sure we are considering a sufficiently broad range of economic, strategic and sustainability criteria in the context of risk and enduring sources of competitive advantage. Investing to maximize value in resilient hydrocarbons: We aim to invest appropriately in our resilient and valuable hydrocarbons business to generate sustainable cash flow. We have set stringent hurdle rates for all final investment decisions. A payback of less than 10 years for all investments in upstream oil and refining. A payback of less than 15 years for upstream gas. Share buyback commitment: We are committing to return at least 60% of surplus cash« as share buybacks, having reached $35 billion
net debt and subject to maintaining a strong investment grade credit rating. Investment in non-oil and gas As part of our net zero ambition (see page 49), we aim to increase the proportion of investment we make into our non-oil and gas businesses. We plan to increase investment in low carbon from around $750 million in 2020 to $3-4 billion by 2025 and to around $5 billion a year in 2030. Our 2020 capital expenditure« against our aim 5 non-oil and gas activities of around $750 million included a partial acquisition payment for the US offshore wind partnership with Equinor, see page 20, our investments in electrification and advanced mobility, and investment into activities through bp ventures and Launchpad. In 2020 Lightsource bp progressed multiple solar projects, including developments in Texas, Indiana, Colorado and Spain. bp Bunge now has capacity for 1.8 billion litres of ethanol production a year and is able to export over 1,200GWh
of electricity to the national grid in Brazil. We expect overall low carbon spend to grow significantly in 2021. Capital expenditure for convenience and mobility grew to $2.2 billion in 2020, weighted towards growth and with a focus on new retail sites«, differentiated fuels and lubricants and next-gen mobility. We formed a joint venture with Reliance in India and plan to scale up to 5,500 retail sites by 2025, see page 24. We made significant progress towards our 2030 aim of more than 70,000 electric vehicle charge points« through the DiDi joint venture in China, investment in ultra-fast electric vehicle charging points in Germany, and bp pulse – the UK’s largest public charging network. Overall, bp transition and low carbon capital expenditure in 2020 was around 20% of the capital mix, and by 2030 we expect it to be as much as 50% of our capital expenditure, of which a significant majority will be low carbon.
Our financial frame As a reminder, the CA100+ resolution« requires us to disclose: Our anticipated investment in oil and gas resources and reserves – this is anticipated to be less in 2021 than it was in 2020. Our anticipated investment in other energy sources and technologies, which is anticipated to be significantly greater than 2020 levels, as described above. To reinvent bp and deliver our strategy, we must operate within a resilient financial frame, that combines a strong balance sheet with cash flow generation to support higher investment into transition businesses and compelling shareholder distributions. 1 Resilient dividend 2 Strong balance sheet 3 Investing at scale in the energy transition 4 Investing to maximize value in resilient hydrocarbons 5 Share buyback commitment
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Strategic report bp Annual Report and Form 20-F 2020 2021 guidance Our investor proposition 2020 actual 2021 guidance Upstream reported production excluding Rosneft 2.4mmboe/d Lower than 2020. Underlying production« slightly higher than 2020 Total capital expenditure« $14.1bn ~$13bn Depreciation, depletion and amortization $14.9bn Similar level to 2020 Gulf of Mexico oil spill payments (post-tax) $1.6bn ~$1bn Other businesses and corporate underlying annual charge $1.0bna $1.2-1.4bn Underlying effective tax rate« -14%b Higher than 40% a Includes an uplift in valuation of a venture investment of $0.3 billion. b Nearest equivalent GAAP measure: effective tax rate 17%. We believe that our strategy and financial frame support the delivery of our investor proposition. Sustainable value Profitable growth Committed distributions through the resilient dividend and our commitment to share buybacks as measured by adjusted EBIDA per share« and
ROACE« through investment in a company that is helping the world decarbonize
24 bp Annual Report and Form 20-F 2020 Reinventing bp – our strategy in action
25 Strategic report bp Annual Report and Form 20-F 2020 Convenience and mobility We aim to become a leading player in India’s fuels and mobility market through our Jio-bp joint venture with
Reliance. The joint venture« will bring together Reliance’s market-leading Jio brand presence with bp’s extensive global experience in convenience, fuel retailing and aviation operations. In addition, Castrol lubricants, India’s number one premium lubricant brand, will also be available across the network. What we’re doing Operating under the Jio-bp brand, we expect to grow Reliance’s current fuel retailing network of more than 1,400 retail sites« to 5,500 by 2025. The joint venture also plans to increase its aviation presence from 30 to 45 airports. Why we’re doing it India is set to be one of the fastest- growing fuels and lubricants markets in the world over the next 20 years, with the number of passenger cars forecast to grow nearly six-fold over that period. We see opportunities over time to shape low carbon mobility solutions for customers in India by supporting the
electrification of two and three- wheel transport and providing battery management solutions. What sets us apart Jio-bp sites will seek to offer Indian consumers high-quality, differentiated fuels and tailored convenience services, benefiting from bp’s global convenience and mobility experience and Reliance’s scale, access and digital connection to millions of customers. Customers will also have access to loyalty offers and our Castrol lubricants. This new venture is a unique opportunity to build a leading, fast-growing business that can help meet India’s demands and create exciting new digital and low carbon options for the future. Bernard Looney Chief executive officer See pages 20 and 34 for more examples of our strategy in action. 5,500 Jio-bp retail sites expected by 2025
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bp Annual Report and Form 20-F 2020 Pursuing a strategy that is consistent with the Paris goals What we mean by Paris consistent We aim to be recognized as a leader in transparency for our sector, in the knowledge that investors and other stakeholders are seeking to understand whether companies and their strategies, targets and aims are consistent with the world meeting the goals of the Paris Agreement on Climate Changea (the Paris goals). This is what we refer to as ‘Paris consistency’. We believe the world is on an unsustainable path – the carbon budget is running out – and needs to reach net zero greenhouse gas emissions. And we believe that there are a range of global pathways to achieve the Paris goals, with differing implications for regions, industries and sectors, so business strategies need to be flexible. Our approach to determining Paris consistency is based on three key principles. We believe that
our strategy satisfies all three principles and therefore the board considers it to be consistent with the Paris goals. 1. Informed by Paris-consistent energy transition scenarios – a company’s strategy should be informed by Paris-consistent scenarios. We see the Intergovernmental Panel on Climate Change (IPCC) as the most authoritative source of information on the evolving science of climate change and we use it and other sources to inform our strategy. The IPCC highlights that there are a range of global pathways by which the world can meet the Paris goals, with differing implications for regions, industries and sectors. For many years to come oil and gas features in the energy mix in the IPCC’s suite of Paris-consistent scenarios, albeit progressively decarbonized and ultimately offset; the exact trajectory for oil and for gas varies from scenario to scenario. bp’s new strategy is informed by all of these considerations.
It is designed to drive progressive decarbonization, while remaining flexible and adaptable to the many different potential pathways the energy transition may take, including various Paris-consistent pathways. 2. Contributing to net zero – whether a company’s strategy enables it to make a positive contribution to the world meeting the Paris goals. We believe that bp’s strategy enables us to make just such a contribution. It is designed to deliver value, while advancing bp towards meeting our net zero ambition and helping the world get to net zero too. Together, we believe this sets out a path that is consistent with the Paris goals. There are many different ways in which a company at the heart of the energy sector can make a meaningful contribution – including action on greenhouse gas emissions (GHG) measured by emissions metrics like Scope 1, 2 and 3. Paris consistency also includes consideration of a range
of other activities, such as technology development, policy advocacy, low carbon collaboration and investments in low carbon. Our strategy seeks to address all of these by reshaping bp’s business around our three focus areas and three sources of differentiation, see page 15. Some ways of contributing are more readily measured by quantitative metrics than others – but all can be important, whether or not they translate into GHG reductions for the company. To illustrate this, in terms of low carbon investment, by 2030 we aim to increase the amount of renewable energy generating capacity we have developed to 50GW, as part of our increased capital expenditure on low carbon businesses. This aim supports the Paris goals by increasing the low carbon options available to energy consumers. However, it does not reduce our Scope 1, 2 or 3 emissions. And it may
not result in a decrease in the overall intensity of bp’s marketed products, because that is dependent on the extent to which we market the resulting renewable power, which is a commercial consideration. Additionally, our strategy is underpinned by our aim to more actively advocate for policies that support net zero, including carbon pricing. Helping policy makers to design and put in place low carbon policies can help deliver our strategy and take advantage of the huge opportunities associated with achieving the Paris goals. Well-designed low carbon policies can advance the decarbonization of a whole economy – something potentially of far greater impact than anything a single company can achieve through its own portfolio. 3. Strategic resilience – a Paris-consistent strategy should position the company for success and resilience in a
Paris-consistent world – a world that is progressing on one of the many global trajectories considered to be Paris consistent, and ultimately meets the Paris goals. We believe this means having a strategy that’s flexible enough to manage the inherent uncertainty in the range of potential global pathways, including those that can achieve the Paris goals. Our new strategy is designed to provide this flexibility. In setting the strategy, the board and management referred to the range of scenarios set out in the bp Energy Outlook 2020, see page 11. We see huge opportunity in the energy transition, including the Outlook’s ‘Rapid’ and ‘Net Zero’ scenarios, which we believe are two of many possible Paris-consistent pathways for the world. Our strategy also mitigates the risks associated with a scenario such as the Outlook’s ‘Delayed and Disorderly’ transition.
As a result, our strategy is designed to be resilient across scenarios, including those that are Paris consistent, but is weighted towards a rapid transition. Reinventing bp – consistency with the Paris goals a Paris Agreement 1 Article 2.1(a) of the Paris Agreement states the goal of ‘Holding the increase in the global average temperature to well below 2°C above pre-industrial levels and pursuing efforts to limit the temperature increase to 1.5°C above pre-industrial levels, recognizing that this would significantly reduce the risks and impacts of climate change’. 2 Article 4.1 of the Paris Agreement: In order to achieve the long-term temperature goal set out in Article 2, parties aim to reach global peaking of greenhouse gas emissions as soon as possible, recognizing that peaking will take longer for developing country parties, and to undertake rapid reductions thereafter in accordance with best available science,
so as to achieve a balance between anthropogenic emissions by sources and removals by sinks of greenhouse gases in the second half of this century, on the basis of equity, and in the context of sustainable development and efforts to eradicate poverty.
27 Strategic report bp Annual Report and Form 20-F 2020 Responding to increased shareholder interest on Paris consistency In 2019 the board recommended that shareholders support a special resolution requisitioned by Climate Action 100+ (CA100+) on climate change disclosures. The CA100+ resolution passed with more than 99% of the vote. This is the second year we have included responses throughout the annual report. We have
adopted a similar approach to the bp Annual Report and Form 20-F 2019. The CA100+ resolution, which includes safeguards such as protections for commercially confidential and competitively sensitive information, is on page 341. Key terms related to this resolution response are indicated with « and defined in the glossary on page 341. These should be reviewed with the following information. Element of the CA100+ resolution Related content Where Strategy that the board considers in good faith to be consistent with the Paris goals. Our strategy Pursuing a strategy that is consistent with the Paris goals 15 26 How bp evaluates each new material capex investment« for consistency with the Paris goals and other outcomes relevant to bp strategy. Our investment process 29 Disclosure of bp’s principal metrics and relevant targets or goals over the short, medium and long term, consistent with the Paris goals. Key performance indicators Sustainability:
net zero targets and aims See ‘TCFD metrics and targets’ for an overview 39 49 55 Anticipated levels of investment in: (i) Oil and gas resources and reserves. (ii) Other energy sources and technologies. Our financial frame 22 bp’s targets to promote operational GHG reductions. Sustainability: net zero targets and aims 49 Estimated carbon intensity of bp’s energy products and progress over time. Sustainability: aim 3 50 Any linkage between above targets and executive pay remuneration. Directors’ remuneration report 2020 annual bonus outcome 2021 remuneration policy on page 103 110 124 Portfolio resilience We are managing our portfolio to be resilient to the uncertainties surrounding the energy transition. By 2030 we expect to have a smaller, more resilient and focused oil and gas portfolio. This is supported by our evaluation of each new material capex investment for Paris consistency and our long-term price
assumptions, which were reviewed in June 2020. We lowered our price assumptions and extended them to 2050 so that they are now consistent with our long-term time planning horizon, see page 28. We are building a portfolio that is more robust in a low carbon world. We believe that the diversification of our portfolio and decarbonizing our hydrocarbons business will make bp more resilient to Paris-consistent pathways. And this will allow us to continue to redeploy capital to support our strategy to become an Integrated Energy Company – aiming to deploy an appropriate mix of cash flow from hydrocarbons and capital released by divestments into ambitious plans for growth in our low carbon, convenience and mobility businesses, see page 18. Scale and reach Our global footprint and interests in multiple sources of energy provide resilience through exposure to different price environments, and our presence in over 70 countries enables access to new
markets. Our track record of creating mutually beneficial strategic partnerships helps our resilience, and we are building new and deeper relationships with governments, cities and corporate customers at a scale that we believe is difficult for others to replicate. Our presence across the energy value chain and our ability to provide integrated energy solutions for our customers position us to succeed in a Paris-consistent world. Targets and aims Our strategy is supported by clear business plans, underpinned by specific short, medium and long-term targets and aims for 2025, 2030 and 2050 or sooner, including: Aiming to be net zero across our entire operations (Scopes 1 and 2). Aiming for the carbon in our upstream oil and gas production (Scope 3) to be net zero. Aiming to cut the life cycle carbon intensity of our marketed products by 50% (which includes the associated Scope 3 emissions). From a 2019 baseline, we aim to increase our annual low carbon
investment ten-fold to around $5 billion a year, building out an integrated portfolio of low carbon technologies, including renewables, bioenergy and early positions in hydrogen and carbon capture, use and storage (CCUS). Over the same period, our oil and gas production is expected to reduce by at least 1 million barrels of oil equivalent a day, or 40%, from 2019 levels.
28 bp Annual Report and Form 20-F 2020 Investment process price assumptions All investments are evaluated against our long-term price assumptions across a range of alternative prices (central, upper and lower) for oil, natural gas and refining margins. In addition, all investment cases above defined
thresholds for anticipated annual greenhouse gas (GHG) emissions from operations must estimate those anticipated GHG emissions and include an associated carbon price into the investment economics. All price assumptions place some weight on scenarios in which the transition to a low carbon energy system is sufficiently rapid to meet the goals of the Paris Agreement, as well as scenarios in which the transition is not, or may not be, sufficiently rapid. They also place some weight on a range of other factors, which can drive prices, and are not related to the goals of the Paris Agreement. These price ranges do not link to specific scenarios or outcomes, but instead try to capture the range of different possibilities surrounding the future path of the global energy system. The nature of the uncertainty means that these price ranges inevitably reflect considerable judgement. The ranges are reviewed and updated on an annual basis as our understanding
and judgement about the energy transition evolves. In addition to consideration of a range of price assumptions, investment cases are asked to present scenarios covering a range of variables, related to the economics of the investment, such as cost, resource, policy changes and schedule, to highlight the robustness of investment cases to a range of other factors. Revising long-term price assumptions Our price assumptions are determined for use in our investment appraisal processes. They are also used to inform decisions about internal planning processes and the impairment testing of assets for financial reporting. What the prices are As part of our strategy development we reviewed our portfolio and capital development plans. That work was informed by bp’s views of the long-term price environment and its balanced investment criteria. Together these create a framework that seeks to ensure investments align with our strategy and add shareholder
value. Additionally, with the COVID-19 pandemic continuing throughout 2020, we see it having an enduring impact on the global economy, with demand for energy weaker than expected for a sustained period. We attach increasing weight to the possibility that the aftermath of COVID-19 will accelerate the pace of transition to a lower carbon economy and energy system, as countries seek to ‘build back better’ so their economies are more resilient and sustainable. As a result of all the above, we revised down our long-term price assumptions, and also extended them to 2050 to align with the horizon of our ambition. The next few years will likely see periods of market volatility as demand recovers against a backdrop of reduced levels of investment and we believe we are well positioned to benefit from any near-term increase in oil prices. The role of long-term price assumptions is to look through this near-term volatility and help ensure
our future projects are resilient to the longer-term trends affecting our industry. Our revised investment appraisal long-term price assumptions are now an average of around $55/bbl for Brent« and $2.90 per mmBtu for Henry Hub« gas (2020 $ real), from 2021- 2050. We consider these lower long-term price assumptions to be broadly in line with a range of transition paths consistent with the Paris goals. However, they do not correspond to any specific Paris-consistent scenario. We also revised our carbon prices for the period to 2050, and these now include a price of $100/teCO2 in 2030 (2020 $ real). Key investment appraisal assumptions 2021 2025 2030 2040 2050 Brent oil ($/bbl) 50 50 60 60 50 Henry Hub gas ($/mmBtu) 3.00 3.00 3.00 3.00 2.75 RMM« 10 12 12 10 10 Carbon price (US$/tCO2e) 2021 2025 2030 2040 2050 Central case real (2020) 50 50 100 200 250 Impairment testing As a result of the revision of long-term price assumptions
used for investment appraisal, we also revised the price assumptions we use in value in-use impairment testing. These two price sets are now aligned. See pages 166-167 for more about oil and natural gas price assumptions used for impairment testing and relating sensitivity testing. Our investment process Price assumptions Reinventing bp – our investment process
29 Strategic report bp Annual Report and Form 20-F 2020 Investment governance and evaluating consistency with the Paris goals Governance bp’s investments fall within a governance framework. This seeks to ensure investments align with our strategy, fall within our prevailing financial frame,
and add shareholder value. The governance framework also provides for investments to be assessed consistently and against a range of other outcomes relevant to our strategy, including a range of environmental and sustainability factors. Investments follow an integrated stage-gate process designed to enable us to choose and develop the most attractive investment cases. A balanced set of investment criteria is used, see page 30. This allows for the comparison and prioritization of investments across an increasingly diverse range of business models. The governance framework also specifies that proposed investments are tested, including against carbon prices for projected operational emissions, and are subject to assurance by functions independent of the business before a final investment decision (FID) is taken. See page 88 for more information on bp’s governance framework. Resource commitment meeting For capital investments above defined
financial thresholds for organic or inorganic spend, the investment approval is conducted by the executive-level resource commitment meeting (RCM), which is chaired by the chief executive officer. The RCM reviews the merits of each such investment case against a balanced set of criteria and considers any key issues raised in the assurance process. The CA100+ resolution requires bp to disclose how we evaluate the consistency of new material capex investments« with (i) the Paris goals and (ii) a range of other outcomes relevant to bp’s strategy. bp’s evaluation of consistency of such investments with the Paris goals was undertaken by the RCM for new material capex investments sanctioned in 2020, see page 31. bp’s evaluation of an investment’s consistency with ‘a range of other relevant outcomes’ is achieved by considering its merits against bp’s balanced investment criteria
as described on page 30. The role of the board The board assesses the impact of portfolio changes, such as strategic acquisitions and the allocation of capital. The board reviews capital investments that are more than $3 billion for resilient hydrocarbons, more than $1 billion for all transition or low carbon investments and, in addition, any significant inorganic acquisition that is exceptional or unique in nature. Reviews investment cases more than $3 billion for resilient hydrocarbons, more than $1 billion for all transition or low carbon investments and any significant inorganic acquisition that is exceptional or unique in nature. bp board Approves investment decisions related to existing and new lines of business above $250 million organic and $25 million inorganic, or which exceeds the relevant EVP financial authority, and for any project considered strategically important such as new market entry. Resource commitment meeting EVP level forums to review
investment cases within a business group as per individual EVP financial authority (up to $250 million organic, $25 million inorganic capital investment). Investment allocation committees SVP level forums which review investment cases within a business group, enabler or integrator up to the individual SVP financial authority. Business unit investment governance meetings Meetings and forums to allow cross-group discussions and integration. Includes Country Forums, Regional Energy Plan Forum, the Carbon Table and Digital Forum. The forums do not hold decision rights, but inform and underpin the decision-making process delivering integration opportunities across bp. Cross-group meetings and forums
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bp Annual Report and Form 20-F 2020 Balanced investment criteria All group-wide investment cases are required to set out the investment merits and are considered against a set of balanced criteria. This standardized approach creates a level playing field for decision making and allows portfolio-wide comparisons of investment cases. Further, the decision to endorse an investment based on the information provided represents bp’s evaluation that the investment is considered consistent with a range of other outcomes, relevant to bp’s strategy. In 2020 the standardized approach for investment cases was reviewed to place a greater focus on our strategy, sustainability and integration value. These changes, and associated nomenclature, ensure our investment framework is consistent with our strategy. When taking investment decisions, we consider six factors, although our decisions may also take other factors into account as appropriate.
Strategic alignment For all investment cases, we consider whether the investment supports delivery of our strategy, see page 18. And if it involves distinctive capability that bp has, or intends to develop, and whether it adds to an existing ‘scale’ business within the portfolio or could help us create one. Safety and risks Investment cases are required to describe risks unique to the project which have a significantly higher probability than usual or have a significantly greater impact (relative to the size of the project) were they to occur. Sustainability All investment cases are considered against appropriate environmental and sustainability considerations, and sustainability measures, including carbon. Investment cases above defined thresholds for anticipated annual greenhouse gas (GHG) emissions from operations must estimate those anticipated GHG emissions and include an associated carbon price in the investment economics. Investment
economics We consider investment economics against a range of measures including internal rate of return, net present value, discounted payback, profitability index and investment efficiency, using a set of scenarios for commodity prices, margins and carbon prices (where relevant). Investments are considered against stringent differentiated hurdle rates. 1. A payback of less than 10 years for all investments in upstream oil, refining and for fuels retail in mature markets; together with an internal rate of return hurdle. 2. A payback of less than 15 years for upstream gas; together with an internal rate of return hurdle. 3. We have a range of sector-specific internal rates of returns of between 10% and 15%. And finally, for renewable power we look for returns of at least 8% to 10% levered. Volatility and rateability Economic metrics are also considered in the context of the cash flow certainty of the investment assumptions. For example, a high-return
deepwater tieback will have less certain and more volatile (oil-price linked) cash flows than a lower return but more certain renewable power project with a long-term power purchase agreement (and a fixed power price). Optionality and integration All investment cases are requested to quantify the strategic optionality that might be accessed through follow-on activity and regular cross-entity forums enable integration opportunities to be identified. For example, an offshore wind development may provide additional optionality for power offtake and integration into our digital platforms. Strategic alignment Safety and risks Sustainability Optionality and integration Investment criteria Volatility and rateability Investment economics Six factors Reinventing bp – our investment process
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Strategic report bp Annual Report and Form 20-F 2020 Evaluation process When evaluating the consistency of our 2020 new material capex investments« with the Paris goals, a focus of the evaluation criteria was on their competitiveness and financial robustness as the prices of different forms of energy and products adjust in response to the changing market environment. For new material capex investment decisions taken from September 2020, the evaluation used our revised central price assumptions of around $55/bbl for Brent« and $2.90 per mmBtu for Henry Hub« gas (2020 $ real), from 2021-2050. It also used our revised central carbon price assumptions, applied to the anticipated operational greenhouse gas emissions associated with the investment, for the period to 2050. These now include a price of $100/teCO2 in 2030 (2020 $ real), see page 28. Our resource commitment meeting (RCM) evaluates consistency with the Paris goals by
considering them against a balanced set of investment criteria, see page 30. For each of the investment criteria, a qualitative explanation of each business case was considered and presented to the RCM or relevant investment committee, as per the description on page 29. Our new material capex investments are intended to support the delivery of bp’s strategy. In-scope investments are defined as: New: investment in a new project or extension of an existing project/asset, or share of an entity that is new to bp or a substantial increase in bp’s share. Material: more than $250 million capital investment. Capital expenditure: includes organic and inorganic. 2020 was an exceptional year, and one aspect of bp’s response was to reduce our planned capital expenditure, see page 9. As a result, there were only three new material capex investments – unusually low, and less than half the number in 2019. So bp decided to
voluntarily conduct and disclose Paris-consistency evaluations for the four largest new capex investments which fell below our materiality threshold. We do not expect to disclose such evaluations of non- material investments in future years. To maintain consistency of approach, the conduct of these evaluations was delegated to a subset of the RCM. Quantitative evaluations Two quantitative guide levels were considered to inform the evaluation of Paris consistency. As stated in the bp Annual Report and Form 20-F 2019, we continue to develop our approach and in 2020 we made a number of improvements, including benchmarking investment economics against our agreed economic investment hurdles; evaluating investments on the revised price assumptions; and setting a lower carbon intensity guide. As our approach matures with experience, we may continue to adjust or supplement these. Investment economics The calculation of internal rate of return (IRR) and discounted
payback uses the ‘central-price’ case for commodity prices and margins and the ‘central’ carbon price. Economic indicators are then benchmarked against the economic hurdles, see page 30. As a guide, we would normally target a minimum threshold of greater than 1.0x on this basis. For clarity, Paris-consistency evaluations for investment decisions made before September 2020 were measured against the previous long-term price assumptions and against the profitability index (PI) measure. For details, see the bp Annual Report and Form 20-F 2019, page 22. Environment and sustainability Where appropriate, we measure the operational carbon intensity« of the investment relative to that of the 2020 portfolio average for the segment or the related business activity (upstream, refining, offshore wind). As a guide, we would normally target a ratio of less than 100%, meaning that the investment is expected to reduce
the average operational carbon intensity of that portfolio. The potential impact of new material capex investments on bp’s greenhouse gas emission targets is a further consideration. There may be instances when new material capex investments are evaluated as consistent with the Paris goals despite either or both of these guide levels not being met.
32 Investment economics Against economic hurdles Sustainability Carbon intensity (%) The respective rankings of investment performance against each of the quantitative guide levels Guide Guide >$250 million Voluntary disclosures >$250 million Voluntary disclosures 1 The 2020 investments have been
ranked against the two guides (as applicable to the evaluation of each investment). As a result, they are ordered differently in each graph above. 2 For one of the investments the operational carbon intensity was not calculated due to the nature of these investments. The projected operational carbon intensity of renewable power businesses is not considered necessary to quantify for these purposes as the relevant operational emissions would not be expected to be significant. bp Annual Report and Form 20-F 2020 Evaluation outcome As shown in the chart, each of the new material capex investments approved in 2020 met the evaluation guides, applicable to the type of investment at the time that the investment decision was made. Each of these investments was evaluated to be consistent with the Paris goals. Similarly, the four additional (non-material) new capex investments in 2020, referred to on page 33, also met the evaluation guides, with the exception of one
investment not meeting the guide level for carbon intensity. This investment was evaluated to be consistent with the Paris goals, based on the role liquefied natural gas (LNG) plays in the energy transition, especially in the Asia Pacific region in which the project is located, and the strength of the investment economics – with a short payback period, delivering short-cycle cash returns and reducing the timeframe during which the investment would be exposed to uncertainties associated with Paris-consistent pathways. In addition, when this investment is benchmarked on the carbon intensity measure against other LNG projects, instead of the upstream portfolio average, it benchmarks towards the low end of the range. Each of the four additional capex investments was evaluated to be consistent with the Paris goals. Reinventing bp – our investment process
33
Strategic report bp Annual Report and Form 20-F 2020 Decisions taken in 2020 Lambert Deep GWF-3 Four-well subsea tieback to the existing Karratha gas plant in Australia. Herschel development Three-well tie-in to the existing Na Kika infrastructure in the US Gulf of Mexico. Shafag-Asiman exploration well Gas exploration well in the Shafag-Asiman field in Azerbaijan. Qattameya Shallow Additional spend to bring the Qattameya gas field in Egypt online. Isabela 3 Single-well tie-in to the Na Kika platform in the US Gulf of Mexico. Galapagos Deep West well Exploration well in ‘Cretaceous Thicks’ play in the US Gulf of Mexico. US offshore wind acquisition Entry into the US offshore wind market through a strategic partnership with Equinor to develop four assets in existing wind leases. In 2020 three new material capex investment decisions qualified for evaluation of Paris consistency, using our materiality threshold of $250 million.
In addition, because there was an unusually low number of new material capex investments in 2020, we also decided to evaluate the Paris consistency of the four largest new capex investments which fell below our materiality threshold.
34 bp Annual Report and Form 20-F 2020 Reinventing bp – our strategy in action
35 Strategic report bp Annual Report and Form 20-F 2020
Resilient and focused hydrocarbons In July 2020, we began production at our major project Atlantis Phase 3 in the US Gulf of Mexico safely and on time, despite the challenges of the COVID-19 pandemic. Since then, we have added a second well and are on schedule to start a third well by April 2021. Why it’s important Atlantis Phase 3 demonstrates our strategic shift towards resilient and focused hydrocarbons for value creation. The project uses world-class existing infrastructure located in the Atlantis field to increase production at higher margin. Drilling completions and offshore construction were executed with zero personal injuries. Harnessing digital and innovation The team used advanced seismic imaging expertise to identify the ‘field within a field’ and designed the new subsea system to access and deliver these barrels. What’s involved? The project includes a subsea production system for eight new wells tied
into Atlantis, which is designed to boost the platform’s production. Building on our track record The start-up of this project marks an important milestone for our resilient and focused hydrocarbons businesses under our new strategy. We started up three other major projects« during 2020: Ghazeer in Oman, Vorlich in the UK North Sea and KG D6 R Cluster in India. We’re on track to deliver on our target since 2016 of 900mboe/d from new major projects by the end of 2021, with 700mboe/d of production capacity online by the end of 2020. 400,000 hours worked offshore Zero injuries Atlantis Phase 3 is a great example of how oil and gas projects support bp’s strategy by focusing our efforts in the basins we know best and close to existing infrastructure. Starlee Sykes SVP, Gulf of Mexico and Canada See pages 20 and 24 for more examples of our strategy in action.
36
bp Annual Report and Form 20-F 2020 Reinventing bp – our organizational model Our organizational model is designed to drive operational excellence and synergies through common processes and economies of scale. The model consists of four business groups… Production & operations Brings the operations of our hydrocarbon business into one place. It is the operational heart of bp, from which we can produce the hydrocarbon energy and products the world needs – safely, cleanly and efficiently. Responsible for: Safe and reliable operations across all of our oil, gas and refining activities, including bpx energy and our strategic investments with Rosneft in Russia. Driving emissions down in our operations. Customers & products Focuses on customers as the driving force for innovating new business models and service platforms to deliver the convenience, mobility and energy products and services of the future.
Responsible for: Convenience offerings at our retail sites«, including snacks, ready meals and coffee. Fuel sales to customers and businesses. Our Castrol lubricants brand sold through numerous channels. Our aviation fuelling business. Next-gen mobility, including our charging businesses. Refining & trading – our oil products businesses. Gas & low carbon energy Brings our energy teams together to create focused low carbon energy solutions. It also pursues the development of decarbonization technologies and potential moves into new value chains such as hydrogen and carbon capture, use and storage. Responsible for: Integrated gas businesses. Onshore and offshore wind. bp’s 50% stake in Lightsource bp. Biopower and biofuels through bp’s 50% stake in bp Bunge Bioenergia. US biogas. Hydrogen and carbon capture, use and storage. Innovation & engineering Home to our central engineering, safety
and operational risk assurance, and digital security authorities. I&E also aims to act as a catalyst for creating value from disruptive opportunities and new business models. Responsible for: Defining bp-wide operating, engineering and digital standards. Research and development. Digital expertise and transformation. Capturing, incubating and scaling ideas from across bp’s global innovation ecosystem, through bp ventures and Launchpad. We will unlock the power of collaborating as one customer- centric, digital and agile team, focused on meeting customers’ needs and delivering products and services fit for today, and a low carbon future. Emma Delaney, EVP customers & products We believe in becoming a company that provides integrated, low carbon energy solutions for our customers – bringing together different forms of energy to give the world what it wants: clean, affordable and firm energy. Dev Sanyal, EVP
gas & low carbon energy We’ve gathered many of our most skilled engineers, technologists, scientists, and entrepreneurs into a single team with a purpose – enabling bp to thrive in the energy transition through innovation at pace and scale. David Eyton, EVP innovation & engineering Our vision is to build a resilient hydrocarbons business that leads the industry. We maintain an uncompromising focus on safety and emissions and constantly challenge ourselves to improve efficiency. Gordon Birrell, EVP production & operations To deliver our net zero ambition and strategy we are reinventing bp
37 Strategic report bp Annual
Report and Form 20-F 2020 Leadership culture We are transforming the culture of bp. It’s all about people and that begins with leadership. In 2020 we undertook a fundamental review of our organization and selected new leaders from the executive level down. These top 120 leaders were selected because they reflected a number of key attributes required to drive bp’s transformation. A track record of delivery. Curious and open-minded. Purpose-driven. Lead through our values – especially safety. Empathetic. From left to right: Emma Delaney EVP, customers & products Dev Sanyal EVP, gas & low carbon energy David Eyton EVP, innovation & engineering Gordon Birrell EVP, production & operations William Lin EVP, regions, cities & solutions Carol Howle EVP, trading & shipping Giulia Chierchia EVP, strategy & sustainability Bernard Looney Chief executive officer
Geoff Morrell EVP, communications & advocacy Kerry Dryburgh EVP, people & culture Eric Nitcher EVP, legal Murray Auchincloss Chief financial officer Regions, cities & solutions brings together the best of bp to build enduring relationships with regions, countries, cities and corporations around the world to provide innovative, integrated and decarbonized energy solutions at scale to help the world reach net zero and improve people’s lives. Trading & shipping harnesses the deep expertise of our existing supply, trading and shipping businesses. bp already has world-leading expertise in the integration of businesses, customers and markets. Communications & advocacy helps translate bp’s strategy into a coherent narrative for staff and society, manages corporate reputation and leads policy, advocacy and campaigns. working with three integrators, to facilitate collaboration and unlock value...
and four teams who serve as enablers of business delivery. Strategy & sustainability embeds sustainability at the top of the organization and forms a single group-wide approach to strategy and capital allocation. Finance stewards bp’s financial frame, maintains financial integrity and manages procurement activities. Legal delivers legal support to bp, focused on material risk, value and growth. People & culture helps bp recruit world-class talent, develops them, and supports them to do their best work. And of this team, 38% are women and 28% identify as racial and ethnic minorities. This is good progress, but still not good enough. As a leadership, we are not yet fully reflective of bp as a whole or the communities in which we operate. See page 57 for more information on diversity and inclusion in bp. See page 38 for more information on our financial reporting segments. See page 78 for our leadership team biographies.
38 bp Annual Report and Form 20-F 2020 Changing how we report Gas & low carbon energya comprises regions with upstream businesses that predominantly produce natural gas, gas trading activities and the group’s renewables businesses, including biofuels, solar and wind. Gas-producing regions were previously reported in the Upstream segment, and our renewables businesses were previously reported as part of Other businesses and corporate. Oil production & operationsa comprises regions with upstream activities that predominantly produce crude oil, including bpx energy. These were previously reported in the Upstream segment. Customers &
products comprises the group’s customer-focused businesses, spanning convenience and mobility, which includes fuels retail and next-gen offers such as electrification, as well as aviation, midstream, and Castrol lubricants. It also includes our oil products businesses, refining & trading. The petrochemicals business will also be reported in restated comparative information as part of customers & products up to its sale in December 2020. This segment is unchanged from the former Downstream segment with the exception of the disposal of our petrochemicals business. The Rosneft segment is unchanged and continues to include equity-accounted earnings from our strategic investment in Rosneft. Other businesses & corporate comprises our innovation & engineering business including bp ventures and Launchpad, regions, cities & solutions; and our corporate activities & functions. a The AGT and Middle East
regions have been further subdivided by asset. See page 36 for our organizational model. Our new financial reporting model functions across the organization to maximize commercial value along integrated value chains. Reinventing bp – our financial reporting segments Gas & low carbon energy Oil production & operations Customers & productsd Rosneft Other businesses & corporate Gas Gas regionsc Gas marketing & trading Integrated gas & power Low carbon energy Low carbon electricity Bioenergy CCUS Hydrogen Oil regionsc Customers: convenience & mobility Convenience Mobility: fuels retail Mobility: next-gen Castrol Aviation, B2B, midstream Products: refining & trading Refining Oil & oil products trading bp ventures Launchpad Corporate activities Rosneft Upstream Rosneft Other businesses & corporate Downstream Mapping our 2020 segment reporting to our 2021 financial
reporting segmentsb As set out in our organization model on page 36, operationally, our hydrocarbon businesses, including refining, will be managed together. However, the financial results of our oil, gas and refining operations will be reported separately, acknowledging opportunities for commercial integration. Gas will be reported together with our low carbon businesses. This recognizes the potential for increasing integration of gas value chains with our low carbon businesses. Refining will be reported as part of the customers & products segment, recognizing the importance of maintaining our integrated fuels value chains. For more information on how our hydrocarbon operations are split between the oil production & operations, gas & low carbon energy, and customers & products segments visit bp.com. b Not a comprehensive list of businesses reported in each segment. c Regions disclosed on bp.com under segment financial
disclosure framework. d Includes respective low carbon results, such as bio co-processing.
39 Strategic report 2019 9826 72 2020 7017 53 2018 7216 56 2017 7918 61 2016 10016 84 Tier 1 process safety events Tier 2 process safety events 2019 0.166 2020 0.132 2018 0.198 2017 0.218 2016 0.211 2019 46.0 2020 41.3 2018 46.5 2017 49.4 2016 50.1 2019 1.4 2020 1.0 2018 1.3 2017 0.5 2016 0.7 bp Annual Report and Form 20-F 2020 Key performance indicators Changes to KPIs We have removed proved reserves replacement ratio from our KPIs, as it no longer serves as a useful measure of our strategic performance. Remuneration To help align the focus of our board and executive management
with the interests of our shareholders, certain measures are used for executive remuneration. Key REM Used for 2020 remuneration policy See page 103 for more information. Measuring our progress We assess our performance across a wide range of measures and indicators that are consistent with our strategy and investor proposition. Our key performance indicators (KPIs) provide a balanced set of metrics that give emphasis to both financial and non-financial measures. These help the board and leadership team assess performance against our strategic priorities and business plans. Our leadership team uses these measures to evaluate operating performance and make financial, strategic and operating decisions. Sustainable operations Tier 1 and 2 process safety eventsa We track tier 1 and tier 2 events and report the aggregated outcome. Tier 1 events are losses of primary containment from a process of greatest consequence, or causing harm to a member
of the workforce, damage to equipment from a fire or explosion, a community impact or exceeding defined quantities. Tier 2 events are those of lesser consequence. Safety Reported recordable injury frequencya Reported recordable injury frequency (RIF) measures the number of reported work-related employee and contractor incidents that result in a fatality or injury per 200,000 hours worked. 2020 performance We had fewer tier 1 and tier 2 process safety events compared with 2019. This may in part be a consequence of decreased activity during the COVID-19 pandemic, but we believe that other, more intentional, factors are also involved, such as our deepening focus on safety leadership, human performance, and the effectiveness of core safety processes, such as permit-to-work. 2020 performance We have seen a decrease in RIF compared with 2019 and maintain our focus to drive zero incidents. Since 2015, RIF rates have decreased around 46%. a This represents
reported incidents occurring within bp’s operational HSSE reporting boundary. That boundary includes bp’s own operated facilities and certain other locations or situations. Greenhouse gas emissions (MtCO2e) We provide data on greenhouse gas (GHG) emissions material to our business on a carbon dioxide-equivalent basis. This particular KPI comprises Scope 1 (direct) emissions of CO2 and methane, for 100% emissions from subsidiaries« and the percentage of emissions equivalent to our share of joint arrangements« and associates«, other than bp’s share of Rosneft. Sustainable GHG emissions reductions (MtCO2e) This measure includes actions taken by our businesses to improve energy efficiency and reduce methane emissions and flaring – all leading to ongoing, quantifiable GHG reductions. These refer to
the GHG emissions on an operational control basisb that would have occurred had we not made the change i.e. they could be absolute in nature or underlying. Since 2019, progress against this target is used as a factor in determining bonuses for eligible employeesc, including executives. 2020 performance Our Scope 1 (direct) equity share emissions decreased by 4.7MtCO2e to 41.3MtCO2e in 2020 (46.0MtCO2e in 2019). The reduction was associated with a number of factors such as divestments, including of our Alaska operations, sustainable emissions reductions, turnarounds, and the impact of COVID-19 on demand. 2020 performance We delivered 1.0Mte of sustainable emissions reductions (SERs) from reduction projects such as flaring in Angola, reduction in water pump fuel gas usage in AGT and in lower emissions from power import at our Gelsenkirchen refinery. b Operational control data comprises 100% of emissions from activities that are operated by bp. c This
figure was around 37,000 in February 2020. It is now around 28,600 (as at 10 March 2021) and has been revised in line with restructuring as part of reinvent bp and reflects a lower headcount overall.
40 2019 0.14 2020 0.12 2018 0.16 2019 25 2020 29 2018 24 2017 21 2016 22 25 30 24 24 23 Women in group leadership People from beyond the UK and US in group leadership 2019 94.4 2020 94.0 2018 95.7 2017 94.7 2016 95.3 2019 94.9 2020 96.0 2018 95.0 2017 95.2 2016 95.2 2019 6.84 2020 6.39 2018 7.15 2017 7.11 2016 8.46 2019 5 2020 4 2018 6 2017 7 2016 6 bp Annual Report and Form 20-F 2020 Key performance indicators continued Methane intensity (%) We define methane intensity
as the amount of methane emissions from our upstream oil and gas operations as a percentage of the gas that goes to market from those operations. This applies to methane emissions within our operational control boundary, where we have the highest degree of control. Methane emissions from non-producing activities, such as exploration drilling, are excluded. In 2020 we set an intensity target of 0.20% by 2025, using a measurement approach. 2020 performance Our methane intensity in 2020 was 0.12%, an improvement from 0.14% in 2019. 2020 performance Both measures increased. As a global business we are committed to increasing the diversity of our workforce and leadership. d Relates to bp employees. Diversity and inclusiond (%) Each year we report the percentage of women and individuals from countries other than the UK and the US among bp’s group leaders. Upstream plant reliability (%) bp-operated upstream plant reliability is calculated taking
100% less the ratio of total unplanned plant deferrals divided by installed production capacity. Unplanned plant deferrals are associated with the topside plant and, where applicable, the subsea equipment (excluding wells and reservoir). Unplanned plant deferrals include breakdowns, which does not include Gulf of Mexico weather-related downtime. 2020 performance Operations were strong in 2020 with plant reliability remaining at 94%. Sustainable operations Downstream refining availability (%) Refining availability represents Solomon Associates’ operational availability for bp-operated refineries. The measure shows the percentage of the year that a unit is available for processing after deducting the time spent on turnaround activity and all mechanical, process and regulatory downtime. Refining availability is an important indicator of the operational performance of our downstream businesses. 2020 performance Refining availability was higher,
reflecting continued strong operational performance in our portfolio. This performance is underpinned by our global reliability programmes. Upstream unit production costs ($/boe) The upstream unit production cost is calculated as production cost divided by units of production. Production cost does not include ad valorem and severance taxes. Units of production are barrels for liquids and thousands of cubic feet for gas. Amounts disclosed are for bp subsidiaries only and do not include bp’s share of equity-accounted entities. 2020 performance Lower production costs compared with 2019 were mainly due to improved efficiency in our operations and divestment impacts. Major project delivery We monitor the progress of our major projects to gauge whether we are delivering our core pipeline of projects under construction on time. Projects take many years to complete,
requiring differing amounts of resource, so a smooth or increasing trend should not be anticipated. Major projects are defined as those with a bp net investment of at least $250 million, or considered to be of strategic importance to bp, or of a high degree of complexity. 2020 performance We started up four major projects in India, Oman, the UK and US.
41 Strategic report 2019 65 2020 64 2018 66 2017 66 2016 73 2019 4.0 2020 -20.3 2018 9.4 2017 3.4 2016 0.1 10.0 -5.7 12.7 6.2 2.6 Profit (loss) for the year attributable to bp shareholders Underlying RC profit for the year (non-GAAP) 2019 2020 2018 2017 2016 25.8 12.2 22.9 18.9 10.7 2019 8.9 2020 -3.8 2018 11.2
2017 5.8 2016 2.8 2019 5.8 2020 -41.4 2018 (4.6) 2017 20.0 2016 29.0 1.1 -41.7 0.5 9.5 55.5 ADS basis Ordinary share basis bp Annual Report and Form 20-F 2020 Employee engagement (%) We conduct an annual employee survey to understand and monitor levels of employee engagement and identify areas for improvement. 2020 performance The overall employee engagement score saw a marginal decline since last year. We are working to identify areas for improvement. Scores prior to 2017 are based on questions on priorities set out in 2012, so the numbers are not directly comparable. Underlying replacement cost profit ($ billion) Underlying RC profit« is a useful measure for investors because it is one of the profitability measures bp management uses to assess performance. It assists management in understanding the underlying trends in operational performance on a comparable year- on-year basis. It reflects the replacement cost of inventories sold in the
period and is arrived at by excluding inventory holding gains and losses« from profit or loss. Adjustments are also made for non- operating items« and fair value accounting effects«. Operating cash flow ($ billion) Operating cash flow is net cash flow provided by operating activities, as reported in the group cash flow statement. Operating activities are the principal revenue-generating activities of the group and other activities that are not investing or financing activities. Financial performance Return on average capital employed (%) Return on average capital employed« (non-GAAP) gives an indication of a company’s capital efficiency, dividing the underlying RC profit after adding back net interest by average capital employed, excluding cash and goodwill. See page 349 for more information including the nearest equivalent GAAP data. Total shareholder return (%) Total shareholder return (TSR) represents
the change in value of a bp shareholding over a calendar year. It assumes that dividends are reinvested to purchase additional shares at the closing price on the ex-dividend date. 2020 performance 2020 underlying RC loss was driven by lower oil and gas prices, significant exploration write-offs and refining margins and depressed demand. Loss for the year attributable to bp shareholders included significant impairments and exploration write-offs. See Financial statements – Notes 4 and 8 for more information. 2020 performance Operating cash flow was lower than 2019, reflecting lower oil and gas realizations, lower refining margins and fuels volumes partly offset by lower tax payments and lower working capital« build. 2020 performance The decrease reflects loss due to the impact of lower oil and gas prices and significant weaker refining margin and depressed demand. 2020 performance Reduced TSR reflects a reduction in the share price
and lower dividend in 2020.
42 bp Annual Report and Form 20-F 2020 Group performance Group performance In the face of many challenges in 2020, we strengthened our finances and drove progress towards our $35 billion net debt target. A resilient balance sheet, a coherent approach to capital allocation and a disciplined approach to investment are the principles which underpin our financial frame. Our strategy and financial frame are expected to drive strong growth, improved returns and a sustainable reallocation of our capital employed toward the energy transition, all in support of creating long-term value for shareholders. Murray Auchincloss Group chief financial
officer Financial and operating performance $ million except per share amounts 2020 2019 2018 Sales and other operating revenues 180,366 278,397 298,756 Profit (loss) before interest and taxation (21,740) 11,706 19,378 Finance costs and net finance expense relating to pensions and other post-retirement benefits (3,148) (3,552) (2,655) Taxation 4,159 (3,964) (7,145) Non-controlling interests 424 (164) (195) Profit (loss) for the year attributable to bp shareholders (20,305) 4,026 9,383 Inventory holding (gains) losses«, before tax 2,868 (667) 801 Taxation charge (credit) on inventory holding gains and losses (667) 156 (198) RC profit (loss)« for the year attributable to bp shareholders (18,104) 3,515 9,986 Net (favourable) adverse impact of non-operating items« and fair value accounting effects«, before tax 16,649 8,263 3,380 Taxation charge (credit) on non-operating items and fair value accounting effects, and certain
foreign exchange impacts on the group’s tax charge for the period (4,235) (1,788) (643) Underlying RC profit (loss)« for the year attributable to bp shareholders (5,690) 9,990 12,723 Dividends paid per share – cents 31.5 41.0 40.5 – pence 24.458 31.977 30.568 Results The loss for the year ended 31 December 2020 attributable to bp shareholders was $20.3 billion, compared with a profit of $4.0 billion in 2019. Adjusting for inventory holding losses, replacement cost (RC) loss was $18.1 billion, compared with a profit of $3.5 billion in 2019. After adjusting RC loss for a net charge for non-operating items of $12.2 billion and net adverse fair value accounting effects of $0.2 billion (both on a post-tax basis), underlying RC loss for the year ended 31 December 2020 was $5.7 billion. The result reflected lower oil and gas prices, significant exploration write-offs and lower refining margins and depressed demand. The
profit for the year ended 31 December 2019 attributable to bp shareholders was $4.0 billion, excluding inventory holding gains, RC profit was $3.5 billion. After adjusting RC profit for a net charge for non-operating items of $7.2 billion and net favourable fair value accounting effects of $0.7 billion (both on a post-tax basis), underlying RC profit for the year ended 31 December 2019 was $10.0 billion, a decrease of $2.7 billion compared with 2018. The decrease was predominantly due to lower oil and gas prices in the Upstream segment and a significantly weaker environment in the Downstream segment. Non-operating items In 2020 the net charge for non-operating items was $12.2 billion, mainly related to impairment charges, a gain on the disposal of our petrochemicals business, certain exploration write-offs (reported within the ‘other’ category), and restructuring costs associated with the reinvent bp programme. The impairment charges mainly
relate to producing assets and principally arose as a result of changes to the group’s oil and gas price assumptions. Impairment charges also include amounts relating to the disposal of the group’s interests in its Alaska business. For more information For a discussion of bp’s financial and operating performance for the year ending 31 December 2018, see bp Annual Report and Form 20-F 2019, pages 36-38 and 50-65 and bp Annual Report and Form 20-F 2018, pages 19-39.
43 Strategic report bp Annual Report and Form 20-F 2020 In 2019 the net charge was $7.2 billion, mainly related to impairment charges, principally resulting from the announcements
to dispose of certain assets in the US and reclassification of accumulated foreign exchange losses from reserves to the income statement on the formation of the bp Bunge Bioenergia joint venture«. See pages 304 and 305 for more information on non-operating items and fair value accounting effects. Taxation The credit for corporate income taxes was $4,159 million in 2020 compared with a charge of $3,964 million in 2019. The decrease mainly reflects the loss in 2020. The effective tax rate (ETR) on the loss for the year in 2020 was impacted by the impairment charges and exploration write-offs. The ETRs for 2020 and 2019 were also impacted by various other one-off items. Adjusting for inventory holding impacts, non-operating items and fair value accounting effects, the underlying ETR in 2020 was lower than in 2019, mainly reflecting the exploration write-offs with a limited deferred tax benefit and the reassessment of deferred tax asset recognition.
The underlying ETR for 2021 is expected to be higher than 40% but is sensitive to the impact that volatility in the current environment may have on the geographical mix of the group’s profits and losses. Underlying ETR is a non-GAAP measure. A reconciliation to GAAP information is provided on page 348. $(5.7)bn underlying replacement cost (RC) loss (2019 profit $10.0bn) $(20.3)bn loss attributable to bp shareholders (2019 profit $4.0bn) $12.2bn operating cash flow« (2019 $25.8bn) $ million Non-operating items 2020 2019 2018 Gains on sale of businesses and fixed assets 2,874 193 456 Impairment and losses on sale of businesses and fixed assets (14,369) (8,075) (860) Environmental and other provisions (212) (341) (758) Restructuring, integration and rationalization costs (1,296) 2 (726) Fair value gain (loss) on embedded derivatives – – 17 Gulf of Mexico oil spill (255) (319) (714) Other (2,554) (78) (372) Total before
interest and taxation (15,812) (8,618) (2,957) Finance costs (625) (511) (479) (16,437) (9,129) (3,436) Taxation credit (charge) on non-operating items 4,345 1,943 510 Taxation – impact of US tax reform – – 121 Taxation – impact of foreign exchange (99) – – (12,191) (7,186) (2,805) % Effective tax rate 2020 2019 2018 Effective tax rate (ETR) on profit or loss for the year 17 49 43 Underlying ETR« (14) 36 38
44 bp Annual Report and Form 20-F 2020 Reporting The group’s organizational structure reflects the various activities in which bp is engaged. At 31 December 2020, bp reported Upstream, Downstream,
Rosneft and Other businesses and corporate. Upstream’s activities included oil and natural gas exploration, field development and production; midstream transportation, storage and processing; and the marketing and trading of natural gas, including liquefied natural gas (LNG), together with power and natural gas liquids (NGLs). For further details of Upstream’s activities during the year see page 308. Downstream’s activities covered convenience and mobility offers, including next-gen mobility to our customers. It also included the refining, manufacturing, marketing, transportation, and supply and trading of crude oil, petroleum, lubricants and petrochemicals products. The Rosneft segment result includes equity- accounted earnings arising from bp’s interest in Rosneft. Other businesses and corporate comprised the biofuels and wind businesses, the group’s shipping and treasury functions, and corporate activities
worldwide. In February 2020 bp announced plans for a future reorganization of the group’s operating segments. The group’s segmental reporting structure described above remained in place throughout 2020 and changes, as described on page 38, were effective from 1 January 2021. $ million 2020 2019 2018 Sales and other operating revenues Upstream 34,197 54,501 56,399 Downstream 162,974 250,897 270,689 Other businesses and corporate 1,716 1,788 1,678 198,887 307,186 328,766 Less: sales and other operating revenues between segments 18,521 28,789 30,010 Total sales and other operating revenues 180,366 278,397 298,756 RC profit (loss) before interest and tax Upstream (21,547) 4,917 14,328 Downstream 3,418 6,502 6,940 Rosneft (149) 2,316 2,221 Other businesses and corporate (683) (2,771) (3,521) Consolidation adjustment – UPII« 89 75 211 (18,872) 11,039 20,179 Net (favourable) adverse impact of non-operating items and fair
value accounting effects Upstream 16,506 6,241 222 Downstream (330) (83) 621 Rosneft 205 103 95 Other businesses and corporate (357) 1,491 1,963 16,024 7,752 2,901 Underlying RC profit (loss) before interest and tax Upstream (5,041) 11,158 14,550 Downstream 3,088 6,419 7,561 Rosneft 56 2,419 2,316 Other businesses and corporate (1,040) (1,280) (1,558) Consolidation adjustment – UPII 89 75 211 (2,848) 18,791 23,080 bp average realizationsa $ per barrel Crude oilb 38.46 61.56 67.81 Natural gas liquids 12.91 18.23 29.42 Liquids« 36.16 57.73 64.98 $ per thousand cubic feet Natural gas 2.75 3.39 3.92 US natural gas 1.30 1.93 2.43 $ per barrel of oil equivalent Total hydrocarbons« 26.31 38.00 43.47 Average oil marker pricesc $ per barrel Brent« 41.84 64.21 71.31 West Texas Intermediate« 39.25 57.03 65.20 Average natural gas marker prices $ per million British thermal units Average Henry Hub« gas priced 2.08 2.63
3.09 pence per therm Average UK National Balancing Point gas price« 24.93 34.70 60.38 $/bbl bp average refining marker margin (RMM)« 6.7 13.2 13.1 a Realizations are based on sales by consolidated subsidiaries« only, which excludes equity-accounted entities. b Includes condensate. c All traded days average. d Henry Hub First of Month Index. Group performance continued
45 Strategic report bp Annual Report and Form 20-F 2020 Upstream Sales and other operating revenues for 2020 were lower due to lower liquids and gas realizations, lower gas marketing and
trading revenues and were further impacted by lower sales volumes. RC loss before interest and tax for the segment included a net non-operating charge of $15,768 million. This primarily relates to impairments associated with revisions to the long-term price assumptions. See Financial statements – Note 5 for further information. Fair value accounting effects had an adverse impact of $738 million relative to management’s view of performance. The 2019 result included a net non-operating charge of $6,947 million, primarily related to impairment charges arising from disposal transactions. Fair value accounting effects had a favourable impact of $706 million relative to management’s view of performance. After adjusting for non-operating items and fair value accounting effects, the underlying RC result before interest and tax was lower in 2020 compared with 2019. This primarily reflected lower liquids and gas realizations and
the impact of writing down certain exploration intangible carrying values. Downstream Sales and other operating revenues in 2020 were lower than in 2019, mainly due to lower crude and product prices and the demand impact of COVID-19. RC profit before interest and tax for 2020 included a net non-operating gain of $479 million. The gain reflected a profit of $2.3 billion on the sale of our petrochemicals business, which was partially offset by restructuring costs and impairments. In addition, fair value accounting effects for 2020 had an adverse impact of $149 million, compared with a favourable impact of $160 million in 2019. After adjusting for non-operating items and fair value accounting effects, underlying RC profit before interest and tax for the year was $3,088 million. The fuels business reported a lower underlying RC profit before interest and tax compared with 2019, due to an exceptionally weak refining environment, with COVID-19 restrictions impacting
refining utilization and fuel volumes. The 2020 result also reflects a higher contribution from supply and trading. Our fuels marketing business demonstrated continued resilience, delivering significant profit in 2020, despite COVID-19 – which adversely impacted retail fuel and aviation volumes by 14% and 50% respectively. Refining loss in 2020 reflects the continued impact of historically low industry margins. Although refining availability« was strong at 96%, utilization was around 6% lower than 2019, due to the impact of COVID-19 on demand. These factors were partially offset by a lower level of turnaround activity and lower costs. In the fourth quarter of 2020, we announced plans to cease production at our Kwinana refinery and convert it to an import terminal, helping secure ongoing fuel supply for Western Australia. We continued to redefine convenience in 2020, delivering a 6% growth in convenience gross margin«.
We also expanded our retail network by more than 1,400 sites, to a total of 20,300, including more than 1,900 strategic convenience sites«. And we completed the formation of Jio-bp, our Indian joint venture with Reliance, helping more than double the number of retail sites in growth markets«, see page 24. We also progressed our electrification agenda, growing our network to 10,100 bp and joint venture operated electric vehicle charge points«, see Our strategy on page 15. The lubricants business reported a lower underlying RC profit before interest and tax compared with 2019 and this reflected significant COVID-19 demand impacts, with volumes 15% lower for the year. We continued to expand our service offer in 2020, growing the number of Castrol branded independent workshops by more than 4,000 to over 28,000 globally. The petrochemicals business reported a lower underlying RC profit before interest and tax compared with 2019,
reflecting the impact of COVID-19 on demand and a significantly weaker margin environment. In December we completed the divestment of bp’s petrochemicals business to INEOS for a total consideration of $5 billion. Final payments, totalling $1 billion, were received in February 2021. For more information see Additional information for Downstream on page 318. Rosneft RC loss before interest and tax for 2020 and RC profit before interest and tax for 2019 for the segment included a non-operating charge of $205 million for 2020 and $103 million for 2019. After adjusting for non-operating items, the underlying RC profit before interest and tax in 2020 primarily reflected lower oil prices and unfavourable foreign exchange and adverse duty lag effects compared with 2019 underlying profit. Financial and operating performance for 2020 also reflected the increased average economic interest that bp holds in Rosneft as a result of Rosneft’s share
buyback programme and the transaction to sell Rosneft’s business in Venezuela in exchange for its own shares, which completed in April 2020. For more information see Additional information for Rosneft on page 320. Other businesses and corporate RC loss before interest and tax for the year ended 31 December 2020 was $683 million (2019 $2,771 million). The 2020 result included a net charge for non-operating items of $318 million, primarily relating to Gulf of Mexico oil spill related costs of $255 million and restructuring costs, partly offset by a gain on disposal (non-operating items in 2019 $1,491 million). In addition, fair value accounting effects had a favourable impact of $675 million. After adjusting for non-operating items and fair value accounting effects, the underlying RC loss before interest and tax for the year ended 31 December 2020 was $1,040 million (2019 $1,280 million). This result mainly reflected an uplift in valuation
of a venture investment of $284 million. Outlook for 2021 From the oil supply side, limited growth from non-OPEC+ countries coupled with active market management from OPEC+ means that for 2021 we anticipate a normalization of the currently high inventory levels. Oil demand is anticipated to recover in 2021. The speed and degree of the rebound depends on governments’ policies and individuals’ self-imposed actions as vaccine distribution proceeds.
46 bp Annual Report and Form 20-F 2020 Oil prices have risen since the end of October, supported by vaccine rollout programmes and continued active supply management by OPEC+ countries. Prices are
expected to remain subject to the decisions of OPEC+, confidence in efforts to manage the rollout of vaccination and further virus control measures. We expect the US gas market to tighten in 2021 as supply declines and demand for LNG exports recovers. The current tightness on global LNG markets and higher US gas prices will lift other regional gas prices. US gas markets are likely to benefit from lower production and a recovery in international LNG demand driven by demand in Asia. In Downstream we expect the outlook for the first part of the year to remain challenged due to COVID-19, but to improve. While COVID-19 has had material impacts at the start of the year, with increased restrictions resulting in lower product demand, we expect this uncertainty to improve subject to the successful rollout of vaccination and virus control measures. Industry refining margins and utilization continue to remain restrained by uncertainty about the pace of demand recovery.
The weak margin environment combined with continued capacity additions in developing markets has prompted a raft of third-party closure announcements. However, these closures are unlikely to be sufficient to see a sustained rebound in margins to pre-COVID levels in 2021. Full-year 2021 underlying production« is expected to be slightly higher than 2020 due to the ramp-up of major projects«, primarily in gas regions, partly offset by the impacts of reduced capital investment and decline in lower-margin gas assets. Reported production is expected to be lower due to the impact of the ongoing divestment programme. Other businesses and corporate charges for 2021, excluding non-operating items, fair value accounting effects and foreign exchange volatility impact, are expected to be $1.2-1.4 billion although the quarterly charge may vary quarter to quarter. Operating cash flow Operating cash flow for the year ended 31 December 2020 was
$12.2 billion, $13.6 billion lower than 2019. Operating cash flow in 2020 reflects $1.8 billion of pre-tax cash outflows related to the Gulf of Mexico oil spill. Compared with 2019, operating cash flows in 2020 reflected lower oil and gas realizations, lower refining margins and lower fuels volumes partly offset by lower tax payments and lower working capital« build. Movements in working capital adversely impacted cash flow in the year by $0.1 billion, including an adverse impact on working capital from the Gulf of Mexico oil spill of $1.6 billion. Other working capital effects, principally a decrease in inventory and other current and non-current assets partially offset by a decrease in other current and non-current liabilities, had a favourable effect of $1.5 billion. bp actively manages its working capital balances to optimize and reduce volatility in cash flow. Operating cash flow for the year ended 31 December 2019 was $25.8 billion,
$2.9 billion higher than 2018. Operating cash flow in 2019 reflected $2.7 billion of pre-tax cash outflows related to the Gulf of Mexico oil spill. Compared with 2018, operating cash flows in 2019 also reflected the favourable effect of an estimated $2.0 billion of lease payments being classified as financing cash flows from 1 January 2019 following the implementation of IFRS 16. Movements in working capital adversely impacted cash flow in the year by $2.9 billion, including an adverse impact on working capital from the Gulf of Mexico oil spill of $2.6 billion. Cash flow and net debt information $ million 2020 2019 2018 Operating cash flow 12,162 25,770 22,873 Net cash used in investing activities (7,858) (16,974) (21,571) Net cash provided by (used in) financing activities 3,956 (8,817) (4,079) Cash and cash equivalents at end of year 31,111 22,472 22,468 Capital expenditure« Organic capital expenditure« (12,034) (15,238) (15,140) Inorganic
capital expenditure« (2,021) (4,183) (9,948) (14,055) (19,421) (25,088) Divestment and other proceeds Divestment proceeds« 5,480 2,201 2,851 Other proceeds 1,106 566 666 6,586 2,767 3,517 Debt Finance debt 72,664 67,724 65,132 Net debt« 38,941 45,442 43,477 Finance debt ratio« (%) 45.9% 40.2% 39.1% Gearing« (%) 31.3% 31.1% 30.0% Gearing including leases« (%) 36.0% 35.3% NA Group performance continued
47 Strategic report bp Annual Report and Form 20-F 2020 Net cash used in investing activities Net cash used in investing activities for the year ended 31 December 2020 decreased by $9.1 billion compared with 2019.
The decrease mainly reflected lower capital expenditure, particularly due to payments of $3.5 billion in 2019 for the acquisition of unconventional onshore US oil and gas assets from BHP, and $3.9 billion of disposal proceeds from the petrochemicals divestment. Total capital expenditure for 2020 was $14.1 billion (2019 $19.4 billion), of which organic capital expenditure was $12.0 billion (2019 $15.2 billion) in line with the guidance given in April. Sources of funding are fungible, but the majority of the group’s funding requirements for new investment comes from cash generated by existing operations. We expect 2021 total capital expenditure, including organic capital expenditure, to be around $13 billion. Total divestment and other proceeds for 2020 amounted to $6.6 billion, including $3.9 billion of proceeds from the petrochemicals divestment and $1.1 billion other proceeds. Other proceeds represented a loan repayment relating to the TANAP
pipeline refinancing; and proceeds in relation to the sale of interests in bp’s retail property portfolio in the UK and New Zealand. Total divestment and other proceeds for 2019 amounted to $2.8 billion, including $0.6 billion received in relation to the sale of an interest in bp’s retail property portfolio in Australia. The proceeds from the UK, New Zealand and Australia property transactions are reported within financing activities in the group cash flow statement. bp has completed or agreed transactions for over half of its target of $25 billion in proceeds by 2025. bp expects proceeds from divestments and other disposals of $4-6 billion in 2021, weighted towards the second half. Net cash provided by (used in) financing activities Net cash provided by financing activities for the year ended 31 December 2020 was $4.0 billion, compared with net cash used of $8.8 billion in 2019. This was mainly due to the issue of perpetual hybrid
bonds with a US$ equivalent value of $11.9 billion. Total dividends distributed to shareholders in 2020 were 31.5 cents per share, 9.5 cents lower than 2019. This amounted to a total distribution to shareholders of $6.3 billion in 2020. In 2019 the total distribution to shareholders was $8.3 billion, of which shareholders elected to receive $1.4 billion in shares under the scrip dividend programme. The board decided not to offer a scrip dividend alternative in respect of the 2020 dividends. Debt Finance debt at the end of 2020 increased by $4.9 billion from the end of 2019. The finance debt ratio at the end of 2020 increased to 45.9% from 40.2% at the end of 2019. Net debt at the end of 2020 decreased by $6.5 billion from the 2019 year-end position. Gearing at the end of 2020 increased to 31.3% from 31.1%, reflecting significant impairments and exploration write- offs, offset by the hybrid bond issue in June 2020. Net debt and gearing are non-GAAP measures.
See Financial statements – Notes 26 and 27 for further information on finance debt and net debt. For information on financing the group’s activities see Financial statements – Note 29 and Liquidity and capital resources on page 306. Group reserves and production (including Rosneft segment)a 2020 2019 2018 Estimated net proved reserves (net of royalties) Liquids (mmb) 10,661 11,478 11,456 Natural gas (bcf) 42,467 45,601 49,239 Total hydrocarbons (mmboe) 17,982 19,341 19,945 Of which: Equity-accounted entitiesb 10,100 9,965 9,757 Production (net of royalties) Liquids (mb/d) 2,106 2,211 2,191 Natural gas (mmcf/d) 7,929 9,102 8,659 Total hydrocarbons (mboe/d) 3,473 3,781 3,683 Of which: Subsidiaries 2,146 2,420 2,328 Equity-accounted entitiesc 1,326 1,360 1,355 a Because of rounding, some totals may not agree exactly with the sum of their
component parts. b Includes BP’s share of Rosneft. See Supplementary information on oil and natural gas on page 231 for further information. c Includes BP’s share of Rosneft. See Oil and gas disclosures for the group on page 312 for further information. Group reserves and production Total hydrocarbon proved reserves at 31 December 2020, on an oil equivalent basis including equity-accounted entities, decreased by 7% compared with 31 December 2019. Natural gas represented about 41% (47% for subsidiaries and 36% for equity-accounted entities) of these reserves. The change includes a net decrease from acquisitions and disposals of 1,069mmboe (decrease of 1,072mmboe within our subsidiaries and increase of 3mmboe within our equity-accounted entities). Acquisition
and divestment activity occurred in our equity-accounted entities in Russia, and divestment activity in our subsidiaries in the US including Alaska. Total hydrocarbon production for the group was 8% lower compared with 2019. The decrease comprised an 11% decrease (6% decrease for liquids and 16% decrease for gas) for subsidiaries and a 2% decrease (4% decrease for liquids and 2% increase for gas) for equity-accounted entities.
48 Embedding into our DN A Eng aging stakeholders Our values
and foundations bp Annual Report and Form 20-F 2020 Our approach to sustainability Sustainability Requirement Relevant policies and standards Information related to policies, any due diligence process and the outcome (a-e) a. Environmental matters Net zero aims TCFD (governance and risk) Sustainability frame Biodiversity position (online) Climate change and the environment – pages 53-57. Managing our environmental impacts – page 56. Our operating management system« (OMS) – page 60. Decision making by the board – page 82. b. Employees Reinvent bp guidelines bp values and code of conduct (online) People and society – pages 57-58. Safety – pages 59-60. Our values and code of conduct – page 61. How we engage with our stakeholders (Pulse survey) – page 63. How the board engaged with stakeholders (Workforce) – page 86. c. Social matters Sustainability frame Managing
our environmental impacts – page 56. Our operating management system – page 60. Value to society – page 58. Decision making by the board – page 82. d. Respect for human rights Business and human rights policy (online) Modern slavery statement (online) Labour rights and modern slavery principles (online) Code of conduct (online) Human rights – page 58. How we engage with our stakeholders (Our human rights policy) – page 63. Our values and code of conduct – page 61. e. Anti-corruption and anti-bribery Anti-bribery and corruption policy Code of conduct (online) Business ethics and accountability – page 61. Our partners in joint arrangements – page 60. Description of principal risks relating to matters (a-e above) – How we manage risk – pages 64-66. Risk factors – pages 67-70. TCFD (climate-related risk management), pages 55-56. Relevant
information Business model description Business model – pages 16-17. Description of non-financial KPIs Key performance indicators – pages 39-41. bp non-financial reporting information statement Produced in compliance with Sections 414CA and 414CB of the Companies Act. Information incorporated by cross reference. Sustainability frame Sustainability is a critical foundation of our strategy. Our new sustainability frame links our strategy to our purpose – to reimagine energy for people and our planet. Our frame focuses on three areas where we believe we can make the biggest difference, with aims and objectives linked to the UN Sustainable Development Goals. Getting to net zero. Caring for our planet. Improving people’s lives. You can read more about our focus areas, sustainability foundations, our work to make sustainability more integral to our thinking and how we’re expanding our engagement with stakeholders
at bp.com/sustainability Reporting on sustainability We updated our sustainability materiality assessment process in 2020 to take into account our new sustainability frame. You can read more about this process in the bp Sustainability Report 2020. For the purposes of this section we have covered material issues, along with additional non-financial information in the following areas: Net zero aims, see pages 49-51. Climate change and the environment, see pages 52-55. Safety, see pages 59-60. People and value to society, see pages 57-58. Business ethics and accountability, see page 61.
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Strategic report Our net zero targets and aims at a glance Aims Aim 1 Aim 2 Aim 3 Aim 4 Aim 5 2020 performance 20% 30-35% 100% 20% 35-40% 100% 5% >15% 50% 0.20%0.12%c 0.6%ab 9%ab 16%a $3-4bn$750m e ~$5bn 2025 target 2030 aims 2050, or sooner, aims Timeline to achieve 50% reduction to follow (based on our new measurement approach)d bp Annual Report and Form 20-F 2020 Our net zero aims In February 2020 we set out our ambition to be a net zero company by 2050 or sooner. And to help the world get to net zero. This ambition is supported by 10 aims: five to help us become a net zero company, and five to help the world meet net zero. Taken collectively, these set out a path that we believe is consistent with the Paris goals. What we mean by net zero When we talk about helping the world get to net zero we mean achieving a balance between sources of anthropogenic
emissions and removal by sinks of greenhouse gases, as set out in Article 4.1 of the Paris Agreementf. When talking about bp becoming a net zero company by 2050, or sooner, in the context of our new ambition and aims 1 and 2, this means achieving a balance between (a) the relevant Scope 1 and 2 emissions associated with our operations (aim 1), or Scope 3 emissions associated with carbon in bp’s net share of production of oil and gas excluding Rosneft (aim 2), and (b) the total of applicable deductions from activities such as sinks, for example carbon capture, use and storage (CCUS) and land carbon projects, which we allow for in our methodology. a Reductions against the 2019 baseline. b The baseline year for our aims 1, 2 and 3 is 2019. Following publication of the bp Annual Report and Form 20-F 2019, some data improvements related to the reported 2019 figures for aims 2 and 3 were identified. Although these are not considered to be material, for each
of aims 2 and 3 the 2019 figure has been adjusted. c The 2020 methane intensity is calculated using existing methodology and, while it reflects progress in reducing methane emissions, will not directly correlate with progress towards delivering the 2025 target under aim 4. d We aim to have this in place by end of 2023. e Aim 5 non-oil and gas activities included a partial acquisition payment for the US offshore wind partnership with Equinor, our investments in electrification and advanced mobility, and investment into activities through bp ventures and Launchpad. f Article 4.1 of the Paris Agreement: In order to achieve the long-term temperature goal set out in Article 2, Parties aim to reach global peaking of greenhouse gas emissions as soon as possible, recognizing that peaking will take longer for developing country parties, and to undertake rapid reductions thereafter in accordance with best available science, so as to achieve a balance between anthropogenic
emissions by sources and removals by sinks of greenhouse gases in the second half of this century, on the basis of equity, and in the context of sustainable development and efforts to eradicate poverty. g See ghgprotocol.org for the full list of categories. Our aim 1 is to be net zero across our entire operations on an absolute basis by 2050 or sooner. This aim relates to our Scope 1 (from running the assets within our operational control boundary) and Scope 2 (associated with producing the electricity, heating and cooling that is bought in to run those operations) GHG emissions. Our performance in 2020 Our combined Scope 1 and Scope 2 emissions, covered by aim 1, decreased by 16% from 54.4MteCO2e in 2019 to 45.5MteCO2e in 2020. Scope 1 (direct) emissions covered by aim 1 decreased by 15% to 41.7MteCO2e in 2020, from 49.2MteCO2e in 2019. Of those Scope 1 emissions, 39.8MteCO2e were from CO2 and 1.9MteCO2e from methane. Scope 2 (indirect) emissions decreased
by 1.4MteCO2e, to 3.8Mte CO2e, a 27% reduction compared to 2019. Decreases resulted from SERs, reduced energy requirement following COVID-19 demand reduction and also include a 1MteCO2e reduction in reported emissions from our Whiting refinery, which in 2020 put an agreement in place to purchase electricity from our Whiting clean energy facility. Our aim 2 is to be net zero on an absolute basis across the carbon in our upstream oil and gas production« by 2050 or sooner. This is our Scope 3 aim and is on a bp equity share basis excluding Rosneft. Emissions are broadly equivalent to the GHG Protocol, Scope 3, category 11g, with the specific scope of upstream production volumes. Our performance in 2020 The estimated emissions from the carbon in our Upstream oil and gas production were equivalent to 328MteCO2e in 2020, a reduction of approximately 9% compared to 361MteCO2eb in 2019.
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bp Annual Report and Form 20-F 2020 Sustainability continued Our aim 3 is to cut the carbon intensity of the products we sell by 50% by 2050 or sooner. This is a lifecycle carbon intensity approach, per unit of energy. It covers marketing sales of energy products and potentially, in future, certain other products, for example, associated with land carbon projects (79.3gCO2e/MJ in 2019a). Streamlined energy and carbon reporting (SECR) information Further information on our greenhouse gas (GHG) emissionsb, energy consumption and energy efficiency is set out below and includes disclosures in respect of the SECR requirements. Operational controlc Unit 2020 2019 2018 2017 Scope 1 (direct) emissions MteCO2e 41.7 49.2 48.8 50.5 UK and offshore MteCO2e 1.7 Global (excluding UK and offshore) MteCO2e 40.0 Scope 2 (indirect) emissionsd MteCO2e 3.8 5.2 5.4 6.1 UK and offshore MteCO2e 0.04 Global (excluding UK and offshore) MteCO2e 3.77 Energy consumptione GWh 180,004 UK
and offshore GWh 7,005 Global (excluding UK and offshore) GWh 172,999 Ratio of Scope 1 (direct) and Scope 2 (indirect) GHG emissions to gross productionf teCO2e/te 0.20 0.22 0.22 0.24 UK and offshore teCO2e/te 0.17 Global (excluding UK and offshore) teCO2e/te 0.20 Energy efficiency measures Since 2016 we have delivered 4.9Mte of sustainable emissions reductions (SERs)« across our operated sites. This is our key metric for tracking annual reductions in greenhouse gas (GHG) emissions from energy efficiency savings and direct GHG emissions. We set annual internal targets for the delivery of SERs across bp. In 2020 we delivered 1MteCO2e of SERs. These included reductions in flaring, direct methane emissions and energy efficiency savings. For example, our operations in the AGT region reduced fuel use for water injection pumps through energy efficiency optimization resulting in a 55kteCO2e reduction of Scope 1 emissions. Further SERs include those delivered
by our US onshore operations, bpx energy of over 245kteCO2e – driving operational efficiencies and substantively reducing our methane emissions profile. Our assets in the Permian region delivered 94kteCO2e of SERs. The largest of these projects was construction and delivery of a centralized facility and electrification of certain operations combined with use of renewable electricity. Our performance in 2020 Average emissions intensity of marketed energy products (gCO2e/MJ)« 2020 2019 Average emissions intensity of marketed energy products 78.8 79.3 Refined energy products 92.6 92.8 Gas products 71.6 71.6 Bio-products 28.2 28.8 Power products 43.0 43.8 bp equity sharebg Our Scope 1 (direct) equity share emissions decreased by 4.7MtCO2e to 41.3MtCO2e in 2020 (46.0MtCO2e in 2019). The reduction was associated with a number of factors such as divestments, including of our Alaska operations, turnarounds, and the impact of COVID-19 on demand.
2020 2019 2018 Scope 1 (direct) emissions 41.3 46.0 46.5 Scope 2 (indirect) emissions 4.2 5.7 5.7 Total 45.5 51.7 52.2 a The baseline year for our aims 1, 2 and 3 is 2019. Following publication of the bp Annual Report and Form 20-F 2019, some data improvements related to the reported 2019 figures for aims 2 and 3 were identified. Although these are not considered to be material, for each of aims 2 and 3 the 2019 figure has been adjusted. b Our approach to reporting GHG emissions broadly follows the IPIECA/API/IOGP Petroleum Industry Guidelines for Reporting GHG Emissions. We calculate CO2 emissions based on the fuel consumption and fuel properties for major sources. We report CO2 and methane. We do not include nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulphur hexafluoride as they are not material to our operations and it is not practical to collect this data. c Operational control data comprises 100% of emissions from activities operated by bp,
going beyond the IPIECA guidelines by including emissions from certain other activities such as contracted drilling activities. d Value rounded to one decimal place. e Energy content of flared or vented gas is excluded from energy consumption reported as although they reflect loss of energy resources, they do not reflect energy use required for production or manufacturing of products. f Gross production comprises upstream production, refining throughput and petrochemicals produced. g bp equity share data comprises 100% of emissions from subsidiaries and the percentage of emissions equivalent to our share of joint arrangements and associates, other than bp’s share of Rosneft. In 2020, while we made progress in increasing the marketed sales of low carbon products, the reduction in the bp carbon intensity was largely a result of the reduction in sales of refined products,
due to COVID-19. See the basis of reporting for the definition of marketed sales and the list of energy products covered at bp.com/basisofreporting.
51 Strategic report bp Annual Report and Form 20-F 2020 Our aim 4 is to install methane measurement at all our existing major oil and gas processing sites by 2023, publish the data, and then drive a 50% reduction in methane intensity« of our operations. And we will work to influence our joint ventures« to set their own methane intensity targets of 0.2%. In 2020 we set an intensity target of 0.20% by 2025, using a measurement approach. To reduce our methane intensity, we will focus on achieving
reductions across our key methane sources. Our performance in 2020 Our methane intensity in 2020 was 0.12%, an improvement from 0.14% in 2019. In 2020 methane emissions from upstream operations, used to calculate our intensity, decreased by 22% to 71.6kt in 2020, down from 92.2kt in 2019. Marketed gas was 3,075bcf in 2020. This reduction in methane intensity was due to the Alaska and bpx energy divestments in 2020 and from SER projects and flaring reductions, the largest reductions being delivered in bpx energy and Angola. Our aim 5 is to increase the proportion of investment we make into our non-oil and gas businesses. Over time, as investment goes up in low and no carbon, we see it going down in oil and gas. We are aiming for up to an eight-fold scaling up of our investment in low carbon energy by 2025 and a ten-fold scaling up by 2030, to around $5 billion a year. In 2020 we invested $750 million, compared to more than $500 million in 2019. See
page 22 for more on our investment in line with aim 5. Five aims to help the world get to net zero Our aim 6 is to more actively advocate for policies that support net zero, including carbon pricing. We have stopped corporate reputation advertising campaigns and this is enabling us to re-direct resources to promote climate policies. In future, any corporate advertising will be to push for well-designed climate policy; communicate our net zero ambition; invite ideas; or build collaborations. We will continue to run recruitment campaigns and advertise our products, services and partnerships – although we aim for these to be increasingly low carbon. We are involved in advocacy activities related to well-designed policies, primarily carbon pricing in the US, through our support for regional initiatives. bp.com/policyandadvocacy Our aim 7 is to incentivize our global workforce to deliver on our aims and mobilize them to become advocates for net
zero. We want to help our employees understand what net zero means and the part they can play – through education and training programmes. We want to incentivize employees, which is why in 2019 we linked our annual cash bonus for eligible employees, including the bp leadership team, to sustainable emissions reductions (SERs). We have exceeded targeted delivery of SERs in both 2019 and 2020, though in 2020, bp decided not to pay an annual bonus due to the prevailing economic and financial environment. In 2020 for senior leaders we increased emphasis on low carbon, moving from 5% to 30% of senior leaders’ equity awards linked to low carbon. And for the bp leadership team, 25% of performance- based pay was linked to delivery of our purpose. The measures for the 2021 annual bonus for the wider workforce are aligned to bp’s strategy and net zero ambition and tied to a balanced scorecard consisting of safety and sustainability, operations
and financial measures. In February 2021, we introduced the reinvent bp share award to incentivize our employees in meeting our aims. All employees will receive a one-off grant of either shares or share options that will become available to keep, sell or transfer in the first quarter of 2025. See the Directors’ remuneration report on pages 103-126 for more detail. Our aim 8 is to set new expectations for our relationships with trade associations around the globe. We belong to associations that offer opportunities to share good practices and collaborate on issues of importance to our sector. We aim for alignment between our policies and those of trade associations that we are a member of but understand that associations’ positions reflect a compromise of the assorted views of the membership. We will make the case for our views on climate change and we will be transparent where we differ. And where we can’t reach alignment,
we will be prepared to leave. We published our first trade associations review in early 2020, and left three associations where we assessed climate positions as not aligned. Since then, we have made interventions where our views have not aligned – these occurred in the area of carbon pricing with the Canadian Association of Petroleum Producers and the Netherlands Employer Association, VNO-NCV. In 2021 we intend to publish an update on our relationships with trade associations which will focus on our engagement with five partially aligned associations. bp.com/tradeassociations Our aim 9 is to be recognized as an industry leader for the transparency of our reporting. On 12 February 2020, we declared our support for the recommendations of the Task Force on Climate-related Financial Disclosures (TCFD). We intend to work constructively with the TCFD and others – such as the Sustainability Accounting Standards Board – to develop
good practices and standards for transparency. See pages 52-55 for our expanded TCFD disclosures. Our aim 10 is to launch a new team to create integrated clean energy and mobility solutions. We launched our regions, cities and solutions team in 2020. It will help countries, cities and corporations around the world decarbonize. We have announced our aim to partner with 10-15 cities globally over the next decade to help them achieve their climate goals. And we will work with three industrial sectors – high tech and consumer products, heavy transport and heavy industries – as they shape their energy transition journeys. In 2020 we’ve formed strategic partnerships with Aberdeen, Houston and Microsoft. We’ve also agreed to provide additional renewable energy to Amazon, helping them toward their ambition to decarbonize. bp.com/RCS
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bp Annual Report and Form 20-F 2020 Sustainability continued The world needs more energy to fuel prosperity and improve standards of living for a growing global population. This energy must be delivered in affordable and reliable ways, but it must also be lower carbon. Climate-related financial disclosures We support the recommendations of the Task Force on Climate-related Financial Disclosures (TCFD), which was established by the Financial Stability Board with the aim of improving the reporting of climate-related risks and opportunities. We announced in 2020 that we intend to work constructively with the TCFD, and others, to develop good practices and standards for transparency. Our latest reporting provides information supporting the TCFD’s recommended disclosures. We responded to the FCA consultation on climate-related financial disclosures and welcome the new listing rule. Governance Recommended disclosure: a. Describe the board’s
oversight of climate- related risks and opportunities. The role of the board is to promote bp’s sustainable success for the benefit of its members, generating value for shareholders while having regard to the interests of our other stakeholders, the impact of our operations on the communities where we operate and the environment. In performing this role, the board is responsible for oversight of the overall conduct of the group’s business, which extends to setting our strategy and approach to the energy transition. The board and its associated committees, including the safety and sustainability, audit, people and governance and remuneration committees, where appropriate, have oversight of climate-related matters, which include climate risks and opportunities. They are updated on these matters frequently, a process which is managed by our company
secretary’s office, which works closely with teams in bp to develop materials that assist the board or committee to discharge its responsibilities, including those related to climate. In 2020 these processes included formal analysis of bp’s net zero ambition and aims, briefings with subject matter experts, reviews of regulatory correspondence regarding prior year climate disclosures, virtual site visits and the preparation and consideration of corporate reporting documents and AGM materials. During 2020, climate matters were included on the agenda at every board meeting. Agendas are now structured along four distinct pillars: strategy, performance, people and governance. The safety and sustainability committee’s remit was extended from the beginning of 2020 to provide oversight of the effectiveness of the implementation of bp’s sustainability frame. This includes reviewing that appropriate progress is being
made against our net zero, people and planet aims. The committee will continue to cover existing sustainability-related activities, including the oversight of operational sustainability risks. The role of the audit committee is to monitor the effectiveness of bp’s financial reporting, systems of internal control and risk management, and the integrity of bp’s external and internal audit processes. In fulfilling this purpose, the committee has oversight of financial disclosure, including TCFD reporting. The role of the remuneration committee is to recommend to the board the remuneration policy for executive directors and the leadership team. It also reviews workforce remuneration and monitors related policies, satisfying itself that incentives and rewards are aligned to bp’s strategy, culture and long-term sustainable success. This includes climate- related matters. The role of the people and governance committee (formerly
the nomination and governance committee) is to oversee a diverse succession pipeline and to review workforce policies and practices, monitoring their consistency with bp’s purpose, strategy and values. This helps ensure that we have the right people to deliver our strategy and net zero ambition. Climate change and the environment Pursuing a strategy consistent with the Paris goals Strategy has been the core focus of every board meeting since the beginning of 2019. Throughout 2020 the board worked closely with the leadership team in developing our new strategy. In August 2020 the chairman outlined the key judgements the board had applied to their decision making regarding bp’s strategy, financial frame and investor proposition. As a result, the board considers that the strategy allows us to be flexible to adapt to market changes and scenarios to remain consistent with the Paris goals. The role of the board in evaluating material
capex consistency with Paris The board assesses the impact of portfolio changes, such as strategic acquisitions and the allocation of capital. It also considers specific investment cases which have been approved by the resource commitment meeting, see page 29. TCFD recommendation: Disclose the organization’s governance around climate- related issues and opportunities. From 1 January 2021, bp implemented a new, simplified system of sustainability governance encompassing the board, its associated committees and the leadership team. This structure will enhance oversight of bp’s new sustainability frame, which focuses on three areas: net zero, people and planet. The remit of the board and its committees under our new governance framework is set out on page 88. Terms of reference for the board and its committees are available at bp.com/governance.
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Strategic report bp Annual Report and Form 20-F 2020 Recommended disclosure: b. Describe management’s role in assessing and managing climate-related risks and opportunities. The assessment and management of climate- related matters is embedded across bp at various levels and delegated authority flows down from the board, see page 29. From 1 January 2021, a new executive level governance forum, the group sustainability committee, will provide internal oversight of bp’s progress against the aims and objectives in the sustainability frame, including net zero. This group is chaired by the EVP strategy & sustainability (S&S) and comprises members of the bp leadership team. The group sustainability committee plans to meet on a quarterly basis to review progress within entities against the sustainability frame and decide on critical strategic positions related to sustainability that present risks or opportunities to delivery.
The EVP S&S will report to the main board and committees as required. The group operational risk committee will continue to provide oversight of safety and operational risk management performance for the group, where appropriate, which includes sustainability-related risks such as modern slavery and severe weather. Board bp leadership team Group sustainability committee Chair: EVP S&S Oversight of sustainability matters. Issues and advocacy meeting Chair: EVP S&S, EVP C&A Policy and advocacy issues, including those related to climate matters. Corporate reporting steering Chair: CFO, EVP C&A, EVP S&S Development and oversight of financial and non-financial reporting, including TCFD. Group operational risk committee Chair: CEO Oversight of the group’s safety and operational risk management performance, safety agenda and priorities. Safety and sustainability committee Audit committee
Remuneration committee People and governance committee bp board level EVP level Sustainability forum Chair: SVP sustainability Focused on sustainability plans and progress. Brings together previously separate committees, including carbon steering group, policy and advocacy, and human rights. Production & operations carbon table Chair: SVP HSE & carbon, P&O Focuses on the delivery of lower carbon plans in P&O – particularly in relation to net zero aims 1 and 4. Meetings and forums to allow cross-group discussions and integration. SVP level Cross bp meetings and forums Climate governance: management of climate-related matters As at 1 January 2021 Climate-related matters were discussed at each of the leadership team meetings in 2020, including the development of bp’s net zero ambition and aims ahead of discussion with the board. The leadership team is supported by bp’s senior-level leadership and
their respective teams, with dedicated business and functional expertise focused on climate-related matters. This includes our health, safety, environment and carbon, strategy and sustainability and group policy and economics teams. Alignment between group, business and functional leaders is fostered through cross- functional bodies.
54 bp Annual Report and Form 20-F 2020 Sustainability continued Strategy Strategic implications of climate change In the bp Energy Outlook 2020 we describe the potential implications of climate change and the energy transition on both primary energy demand and the energy system, through three long-term scenarios: Rapid, Net Zero and Business-as-usual. These
are summarized on page 11 and further analysis by country and region, energy sector and fuel type can be found in the bp Energy Outlook, available at bp.com/energyoutlook. The transition to a lower carbon economy presents both risks and significant business opportunities for bp. Climate-related physical and transition risks are managed and reported as part of our group-wide risk management process described on pages 64-66. Climate-related risks and opportunities associated with the energy transition were taken into consideration alongside other inputs in developing our new ambition, aims and strategy. For more information about how our new organizational model and financial reporting segments see pages 36-38. For more on our new financial frame see page 22. Strategic resilience We believe our strategy is resilient to the range of energy transition pathways and scenarios including Paris, see page 11. For more information on our financial resilience, including
our revised long-term price assumptions and impairment testing, see page 28. For information on the resilience of our individual investments, including our governance structure and investment process, see page 29. Our strategy is validated annually by the board to ensure it remains relevant and resilient, as part of our standard governance processes. Elements of the strategy may be refreshed earlier if there are significant changes in external or internal environment. TCFD recommendation: Disclose the actual and potential impacts of climate-related risks and opportunities on the organization’s business, strategy and financial planning where such information is material. Recommended disclosure: a. Describe the climate-related risk and opportunities that the organization has identified over the short, medium, and long term. b. The impact of climate-related risks and opportunities on the organization’s businesses, strategy, and financial
planning. c. The resilience of the organization’s strategy, taking into consideration different climate- related scenarios, including a 2°C or lower scenario. Our strategy to become an Integrated Energy Company, and our net zero ambition and aims are set out on pages 2-3, 15 and 49. In developing this strategy, the board and leadership team consider a wide range of opportunities and risks across three discrete time horizons: Short term (to 2025): the next five years are defined by detailed business and financial plans, which are performance managed in delivery of our 2025 targets. Medium term (to 2030): looking out 10 years enables us to think beyond the short-term to consider signposts and milestones towards the longer-term scenarios, enabling us to adjust course if required. Long term (to 2050): recognizing the wide range of uncertainties, we use a scenario planning approach to help us explore possible pathways for the energy transition
over the next 30 years, as the world moves towards net zero. This includes consideration of changes in policy, societal preferences, economic growth and technological progress. For more detail on our approach and how it informs our strategy, see page 11. TCFD recommendation: Disclose how the organization identifies, assesses and manages climate-related risks. Risk management Recommended disclosure: a. Describe the organization’s processes for identifying and assessing climate-related risks. bp’s risk management system, described on page 64, is designed to address all types of risks including our principal risks and uncertainties described in Risk factors on page 67. As part of this system our operating businesses, integrators and enablers (see page 36) are responsible for identifying, assessing, managing, and monitoring risks associated with their business area. Risks are assessed in line with bp’s risk management policy
and this includes an impact and likelihood assessment which supports relative prioritization. Climate-related risks are classified in alignment with TCFD’s description of physical and transition risks: Physical risks – risks related to the physical impacts of climate change including event- driven risks such as changes in the severity and/or frequency of extreme weather events. Transition risks – risks related to the transition to a lower carbon economy including policy and legal, technology, markets and reputational risks. The potential material impacts of such climate- related risks are described in Risk factors, see page 67. Recommended disclosure: b. Describe the organization’s processes for managing climate-related risks. c. Describe how processes for identifying, assessing and managing climate-related risks are integrated into the organization’s overall risk management. Risks which may be identified
include potential effects on operations at asset level, performance at business level and developments at regional level from extreme weather or the transition to a lower carbon economy.
55 Strategic report bp Annual Report and Form 20-F 2020 As part of our annual planning process we review the group’s principal risks and uncertainties. Climate change and the transition to a lower carbon economy has been identified as a principal risk, see page 68. This covers various aspects of how risks associated with the energy transition could manifest. Similarly, physical climate-related risks such as extreme weather are covered in our principal risks related to safety
and operations. Our processes for identifying, assessing, managing and monitoring climate-related risks are integrated into bp’s risk management policy and the associated risk management procedures. Examples of how physical and transition climate-related risks are identified, assessed and managed: In the North Sea and Gulf of Mexico, regions more prone to severe weather conditions, our Our group-wide principal metrics and relevant targets/goals TCFD recommended disclosures Section of report Where a. Disclose the metrics used by the organization to assess climate-related risks and opportunities in line with its strategy and risk management process Our strategic focus areas, including low carbon electricity and energy and convenience and mobility 2025, 2030, 2050 metrics, page 18 (in table). Five aims to get to net zero, page 49 (in table). Our financial frame: investing at scale in the energy transition Sector specific IRR hurdle rates
for transition and low carbon investments, page 22. Balanced investment criteria, page 30. Renewable power returns, page 22. Our investor proposition: 2021 guidance Total capital expenditure, page 23. Price assumptions Key investment appraisal assumptions, page 28 (in table). Carbon price (in table). Investment criteria Investment economics, page 30. Evaluating material new capex for consistency with Paris goals Quantitative evaluations, page 31. Investment economics: IRR and discounted payback. Environment and sustainability: operational carbon intensity«. KPIs Key performance indicators, page 39. Sustainability: water and biodiversity metrics Managing our environmental impacts, page 56. Remuneration Directors’ remuneration report Director’s remuneration report, page 103. 2020 annual bonus outcome, page 110. 2021 remuneration policy on a page, page 124. Incentivizing our employees to advocate for net zero Aim 7, page
51. b. Disclose Scope 1, Scope 2, and, if appropriate, Scope 3 greenhouse gas (GHG) emissions, and the related risks. Sustainability: GHG emissions SECR table, page 50. Ratio of Scope 1 and 2 emissions: gross production, page 50. TCFD: risk management, page 54. Risk factors, page 67. For further GHG metrics see bp.com/ESGdata c. Describe the targets used by the organization to manage climate-related risks and opportunities and performance against targets. Sustainability: net zero aims Aim 1-5 summary of 2020 performance, 2025 targets and 2030 aims, page 49. Aim 1 performance (Scope 1 and 2), page 49. Aim 2 performance (Scope 3), page 49. Aim 3 performance (emissions from the carbon in our upstream oil and gas production), page 50. Aim 4 performance (methane) page 51. offshore facilities monitor meteorological and oceanographic conditions through collection of measurements at these facilities. These data are collated and periodically compared
against the Basis of Design for the facility. If significant differences are observed, then this may trigger an update to the Basis of Design, prompting action to re-assess risks such as structural integrity and station-keeping and if necessary, implement additional risk mitigations. Updates may also occur as a result of other new knowledge, analysis methods and data. Transition risks are typically identified and managed by business, regional or central teams. For example, our strategy & sustainability team has identified risks relating to evolving policies across different regions. They work with bp’s leadership as well as with both central and regional legal teams, communications & advocacy and external advisors to manage and monitor these risks. TCFD recommendation: Disclose the metrics and targets used to assess and manage relevant climate-related risks and opportunities where such information is material. Metrics and
targets We present the principal group-wide metrics and targets used to assess and manage climate- related risks and opportunities below. This also addresses the CA100+ resolution requirement to disclose the company’s principal metrics and relevant targets or goals consistent with the Paris goals. We consider this to cover the principal metrics used at group level to help monitor progress on delivery of our strategic consistency with the Paris goals – including our net zero aims. In addition, we report on selected energy group illustrative metrics«. A reference table of these can be found at bp.com/sustainability.
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bp Annual Report and Form 20-F 2020 Sustainability continued Our health, safety, security and environmental (HSSE) goals are: no accidents, no harm to people and no damage to the environment. We work hard to avoid, mitigate and manage our environmental and social impacts over the life of our operations. The way our businesses around the world are expected to understand and manage their environmental and social impacts is set out in our operating management system« (OMS). This includes requirements on engaging with stakeholders who may be affected by our activities. In planning our projects, we identify potential impacts from our activities in areas such as land rights, water use and protected areas. We use the results of this analysis to identify actions and mitigation measures and look to implement these in project design, construction and operations. Our OMS requires each of bp’s operating businesses and functions to create and
maintain its own OMS handbook, describing how it will carry out its local operating activities. Through self-verification, local business processes are reviewed and areas for improvement are prioritized, allowing focus on delivering safe, reliable and compliant operations. Air emissions We monitor our air emissions and put measures in place to reduce the potential impact of our activities on local communities. As part of our aim 19 we plan to evaluate the air emissions from our global operating facilities to better understand how they may be affected while advancing our net zero aims for GHG emissions. For more on air emissions, see the bp Sustainability Report 2020. Caring for our planet Our sustainability frame includes a focus on making a positive difference to the environment in which we operate. The scope of our care for our planet aims covers biodiversity, water management, nature-based solutions including those that reduce or remove carbon,
circularity and sustainable purchasing. Water We actively manage our freshwater demands in areas of stress and scarcity. Based on analysis using the World Resources Institute Aqueduct Global Water Risk Atlas, four of our 24 major operating sites were located in regions with high or extremely high water stress in 2020, with another four in areas of medium to high water stress. This number reduces to three in regions with high or extremely high water and three in regions of medium to high water stress, if our bp petrochemicals and other 2020 divestments are excluded. In 2020 we saw a 2% fall in freshwater withdrawals and a 17% fall in freshwater consumption compared to 2019. This was largely due to the divestment of our Alaskan operation in 2020, the formation of the bp Bunge non- operated joint venture from bp operated biofuels and biopower businesses at the end of 2019 and a reduction in freshwater use in our bpx energy operations during 2020. We have
set an aim to be water positive by 2035. We aim to replenish more freshwater than we consume in our operations. We will do this by being more efficient in operational freshwater use and effluent management, and by collaborating with others to replenish freshwater in stressed and scarce catchment areas where we operate. Biodiversity We have set an aim to enhance biodiversity, focusing on making a positive impact through our actions to restore, maintain and enhance biodiversity where we work. We expect that from 2022 all new bp projects in scope will have plans in place aiming to achieve net positive impact (NPI), with a target for 90% of actions to be delivered within five years of project approvala. We also aim to enhance biodiversity at our major operating sites and support biodiversity restoration and sustainable use of natural resource projects in the countries where we have current or growing investments. In 2020 we launched our new biodiversity position
and focused on sharing it with our stakeholders and putting in place the resources to deliver it. We also started work on defining our NPI methodology with Fauna & Flora International, which we expect to complete at the end of 2021. bp.com/biodiversity Our aims to care for our planet: Aim 16: enhance biodiversity. Aim 17: water positive. Aim 18: championing nature-based solutions. Aim 19: unlock circularity. Aim 20: sustainable purchasing. bp.com/planet a Applicable projects that have the potential for significant direct impacts on biodiversity. Only actions that are intended to be delivered within five years in accordance with the NPI methodology are included. The 30% and 90% targets apply in aggregate across all applicable projects that meet the relevant timeframes from the final project approval (and are not targets for individual projects). Managing our environmental impacts
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Strategic report bp Annual Report and Form 20-F 2020 Number of employees at 31 Decembera 2020 2019 2018 Upstream 13,700 16,600 16,900 Downstream 41,300 44,300 42,700 Other businesses and corporate 8,600 9,200 13,400 Total 63,600 70,100 73,000 a Reported to the nearest 100. For more information see Financial statements – Note 35. Our people are the most important element of our success. We need a motivated, engaged, and diverse workforce to deliver our purpose and strategy. We promote a culture that generates the diversity of thought, approach and ideas needed to reimagine energy and move to a low carbon environment. The people and culture committee helps facilitate the CEO’s oversight of people related matters. In 2020 the committee discussed key items, including our remuneration policy, progress in our diversity and inclusion programme, employee engagement, workplace, our talent and learning programmes and long-term people priorities.
The committee also spent significant time focusing on the reinvent bp programme and related design and selection activities. Attraction and retention We aim to recruit talented people from diverse backgrounds, and invest in training, development and competitive rewards for all our people. We invest in employee development – with a focus on driving safe, reliable and compliant operations, and on building technical, functional and leadership capability. This includes a range of development opportunities for our people through a mix of on-the-job learning, developmental relationships with mentors, managers and peers, and training delivered face-to-face, virtually and through simulation or e-learning. bp’s success depends on having a talented and diverse workforce that represents the communities we serve. Reinvent bp selection process As part of our work to reinvent bp we are running selection processes and considering in-scope employees
for roles within the new organizational design, with the outcome that around 10,000 employees will leave bp by early 2022. The selection processes focus on office-based non-operational roles. We have put robust steps in place to help ensure that the selection processes are fair and objective and that employees are supported before and after receiving their selection outcome confirmation. We have appointed and coached neutral observers to challenge selection decisions and help mitigate unconscious bias and trained line managers on how to undertake fair and meritocratic selection decisions. Where roles are impacted by the selection processes, bp adheres to local laws. Line managers were given supporting resources for the notification process, including guides, training and scripts on communicating outcomes compassionately. We will continue to provide these resources throughout the remaining selection processes. Employees were provided with supporting
resources, including guidance on preparing for change, mental wellbeing, preparing for outcome conversations, and dealing with uncertainty. Employees were encouraged to use the Employee Assistance Programme throughout. We also established our myFuture programme, which provides tools, resources and support to help leavers navigate the next stage in their career or phase of life. See pages 36-37 for more on reinvent bp and our new organizational model. Diversity Our mission is to create an environment in which everyone can bring their best and true selves to work, to reach their potential and support the reinvention of bp. Ethnic diversity In 2020 we published our UK and US frameworks for action to help combat racial injustice in bp. Both frameworks have three key focus areas: transparency, accountability and talent. Those actions will include: publishing a comprehensive global diversity & inclusion (D&I) report in 2021, embedding expectations
and metrics on D&I delivery in our operating plans, reporting externally on our UK ethnicity pay gap annually and doubling our spend with US-based diverse suppliers by 2023. A total of 30% of our group leaders came from countries other than the UK and the US in 2020 (2019 25%). Gender equality The gender balance across bp as a whole is improving, with women representing 39% of bp’s total population (2019 38%). 38% of our 120 newly-appointed extended leadership team are women and our goal is to increase this. At the end of 2020 we had five female directors (2019 5) on our board. Our people and governance committee remains mindful of diversity when considering potential candidates. For more information on the composition of our board, see page 74. Workforce by gender As at 31 December 2020 Male Female Female % Board directors 6 5 45 Leadership team 8 4 33 Group leaders 193 77 29 Subsidiary directors 1,351 284 17 All employees 38,826
24,719 39 bp.com/ukgenderpaygap Inclusion To promote an inclusive culture we provide leadership training and support employee-run advocacy groups in areas such as gender, ethnicity, sexual orientation and disability. As well as bringing employees together, these groups support our recruitment programmes and provide feedback on the potential impact of policy changes. Each group is sponsored by a senior executive. We aim to provide equal opportunity in recruitment, career development, promotion, training and reward for all employees – regardless of ethnicity, national origin, religion, gender, age, sexual orientation, marital status, disability, or any other characteristic protected by applicable laws. Where existing employees become disabled, our policy is to engage and use reasonable accommodations or adjustments to enable continued employment. Employee engagement Our managers hold team and one-to-one meetings with their team members, complemented
by formal processes through works councils in parts of Europe. We regularly communicate with employees on factors that affect bp’s performance, and seek to maintain constructive relationships with labour unions formally representing our employees. People and society
58 bp Annual Report and Form 20-F 2020 Sustainability continued To understand what our employees think and feel about bp, we run an annual ‘Pulse’ survey as well as ‘Pulse Live’ surveys, which enable us to monitor changes in employee sentiment on a weekly basis. The overall employee engagement positivity score in our 2020 annual survey was 64% (2019
65%). Pride in working for bp was 75% (2019 75%). Employees participating in the 2020 Pulse survey told us they strongly supported the launch of bp’s new purpose and ambition in February and the strategy announcement in August. Initial positivity over the strategy waned in December, with employees expressing anxiety about the reinvent process and economic uncertainty during 2020. Most participants felt confident in bp’s approach to managing the impact of the COVID-19 pandemic. Employees also told us we should focus on addressing workload, supporting health and wellbeing and being transparent about the new structure. Share ownership We continue to encourage employee share ownership and have a number of employee share plans in place. For example, we operate a ShareMatch plan in more than 50 countries, matching bp shares purchased by our employees. We also make annual share awards as part of our total reward package all for senior
and mid-level employees globally, and a portion of our more junior professional grade staff. In February 2021, we introduced the reinvent bp share award to incentivize our employees in meeting our aims. All employees will receive a one-off grant of either shares or share options that will become available to keep, sell or transfer in the first quarter of 2025. Wellbeing and mental health Mental health and physical wellbeing are priorities for us and we recognized that the COVID-19 pandemic had direct and indirect consequences for our employees and their families. We offered access to a range of facilities and services, including support through our well-established Employee Assistance Programme and new interventions, including providing access to the Headspace app to both employees and their partners. Our annual global physical wellbeing programme had 5,887 participants from 59 countries, with positive feedback on helping keep teams connected and keeping
people physically active. We continue to improve our systematic management of health data points and sources, to identify where we can target preventive interventions and provide training, support and resources to help improve employee wellbeing and performance. We believe wellbeing at work is becoming part of the bp language – a critical part of caring for our people and the communities in which we operate. Value to society Improving people’s lives One of our sustainability frame areas of focus is to improve people’s lives. We have set five people aims focusing on where bp can make the biggest difference. We want people to benefit from our presence in their local communities, wherever we run projects or operate. This includes collaborating with local communities to support sustainable livelihoods and build greater resilience as part of a just transition. Our work on sustainable livelihoods to date supports several of
the UN Sustainable Development Goals, in particular on education, health and economic growth as drivers for sustainable livelihoods. Human rights We believe everyone deserves to be treated with fairness, respect and dignity. At bp we strive to conduct our business in a responsible way, respecting the human rights of our workers and everyone we come into contact with. Our human rights policy and our code of conduct help us do that. See page 63 for information on how we updated our business and human rights policy in 2020. We respect internationally recognized human rights as set out in the International Bill of Human Rights and the International Labour Organization’s Declaration on Fundamental Principles and Rights at Work, including the core Conventions. These include the rights of our workforce and those living in communities potentially affected by our activities. We incorporate the UN Guiding Principles on Business and Human Rights, which
set out how companies should prevent, address and remedy human rights impacts, into our business processes. When working to remediate any impacts on the rights of local communities we are open to co-operating in good faith to agree remedial actions through state-led mechanisms such as the Organisation for Economic Co-operation and Development National Contact Points. We recognize the importance of accessible and effective operational-level grievance mechanisms in addressing our impacts. bp.com/humanrights Our aims to improve people’s lives: Aim 11: more clean energy. Aim 12: just transition. Aim 13: sustainable livelihoods. Aim 14: greater equity. Aim 15: enhance wellbeing. bp.com/people
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Strategic report 0 20 40 60 80 100 Tier 1 Tier 2 Process safety events Number of incidents 17 26 161816 53 72 56 61 84 2019 2020201820172016 Recordable injury frequency Workforce incidents per 200,000 hours worked 2019 2020201820172016 0.30 0.340.350.33 0.18 0.20 0.19 0.21 0 0.1 0.2 0.3 0.4 Workforce 0.211 0.218 0.198 0.166 0.132 Employees 0.194 0.202 0.152 0.128 0.094 Contractors 0.222 0.229 0.233 0.193 0.163 American Petroleum Institute US benchmark* International Association of Oil & Gas Producers benchmark* * API and OGP 2020 data reports not available until May 2021. bp Annual Report and Form 20-F 2020 Safety Safety is our core value and permeates everything we do. In 2020 it remained our first priority throughout our transformation process and the COVID-19 pandemic. Fundamentally, safety is about caring for our employees and the communities in which we operate. We have taken steps to help our employees operate safely during the COVID-19 pandemic. Tragically,
we saw one fatality related to illness, rather than a process safety incident, in our operations in 2020. This occurred in December in our Indonesian operations when an employee died following COVID-19 infection contracted on site. We deeply regret this loss and offer our deepest condolences to the employee’s family. See page 8 for more information. Keeping people safe All our employees and contractors have the responsibility and the authority to stop unsafe work. Our safety rules guide our workers on staying safe while performing tasks with the potential to cause most harm. The rules are aligned with our operating management system (OMS) and focus on areas such as working at heights, lifting operations and driving safety. We monitor and report on key workforce personal safety metrics in line with industry standards. We include both employees and contractors in our data. We have seen improvements in personal safety in 2020 and while this
may in part be a consequence of decreased activity during the COVID-19 pandemic, we also believe that other, more intentional factors, are involved – namely the groundwork we have done over the past few years, including our deepening focus on safety leadership, human performance, and the effectiveness of our safety processes such as permit-to-work. Our recordable injury frequency, reduced from 0.166 in 2019 to 0.132 in 2020. There is always more we can do, and we remain focused on further improving our results. 2020 2019 2018 Recordable injury frequencya 0.132 0.166 0.198 Day away from work case frequencyb 0.044 0.047 0.048 Severe vehicle accident rate 0.01 0.05 0.04 a Incidents that result in a fatality or injury per 200,000 hours worked. b Incidents that result in an injury where a person is unable to work for a day (shift) or more per 200,000 hours worked.
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bp Annual Report and Form 20-F 2020 Sustainability continued Managing safety bp-operated businesses are responsible for identifying and managing operating risks and bringing together people with the right skills and competencies to address them. Our safety and operational risk assurance team works alongside bp-operated businesses to provide oversight and technical guidance, while our group audit team visits sites on a risk-prioritized basis to check how they are managing risks. Our operating management system Our OMS is a group-wide framework designed to help us manage risks in our operating activities and drive performance improvements. It brings together bp requirements on health, safety, security, the environment, social responsibility and operational reliability, as well as related issues, such as maintenance, contractor relations and organizational learning, into a common management system. Our OMS also helps us improve the quality of our activities
by setting a common framework that our operations must work to. We review and amend these requirements from time to time to reflect our priorities. Any variations in the application of our OMS, in order to meet local regulations or circumstances, are subject to a governance process. Recently acquired operations need to transition to our OMS. Preventing incidents We carefully plan our operations, with the aim of identifying potential hazards and having rigorous operating and maintenance practices applied by capable people to manage risks at every stage. We design our new facilities in line with process safety, good design and engineering principles. We track our safety performance using industry metrics such as the American Petroleum Institute recommended practice 754 and the International Association of Oil & Gas Producers recommended practice 45. Our process safety performance improved from 2019 and was roughly comparable to 2018 and 2017.
There were 35% fewer tier 1 process safety events in 2020 compared to 2019, but our performance was broadly in line with the previous three years. We also recorded 26% fewer tier 2 process safety events compared to 2019, lower than the previous 10 years. The combined tier 1 and tier 2 process safety events were down 29% in 2020 compared to 2019. We investigate incidents including near misses. And we use leading indicators, such as inspections and equipment tests, to monitor the strength of controls to prevent incidents. 2020 2019 2018 Tier 1 and tier 2 process safety eventsa 70 98 72 Oil spills – numberb 121 152 124 Oil spills contained 70 90 63 Oil spills reaching land and water 46 58 57 Oil spilled – volume (thousand litres) 784 710 538 Oil unrecovered (thousand litres) 494 300 131 a Tier 1 process safety events are losses of primary containment of greatest consequence – such as causing harm to a member of the workforce,
costly damage to equipment or exceeding defined quantities. Tier 2 events are those of lesser consequence. b Number of spills greater than or equal to one barrel (159 litres, 42 US gallons). Emergency preparedness The scale and spread of bp’s operations means we must be prepared to respond to a range of possible disruptions and emergency events, such as the COVID-19 pandemic. We maintain disaster recovery, crisis and business continuity management plans and work to build day-to- day response capabilities to support local management of incidents. Security We monitor for hostile actions that could harm our people or disrupt our operations. These actions might be connected to political or social unrest, terrorism, armed conflict or criminal activity. We take these potential threats seriously and assess them continuously. Our 24-hour response information centre in the UK uses state-of-the-art technology to monitor evolving high-risk situations
in real time. It helps us to assess the safety of our people and provide them with practical advice if there is an emergency. Cyber security The severity, sophistication and scale of cyber attacks continues to evolve. The increasing digitalization and reliance on IT systems makes managing cyber risk an even greater priority for many industries, including our own. The risk comes from a variety of cyber-threat actors, including nation states, criminals, terrorists, hacktivists and insiders. As with previous years, we’ve experienced threats to the security of our digital infrastructure, but none of these had a significant impact on our business in 2020. We have a range of measures to manage this risk, including the use of cyber-security policies and procedures, security protection tools, continuous threat monitoring and event detection capabilities, and incident response plans. We also conduct exercises to test our response to and recovery from
cyber attacks. To encourage vigilance among our staff, our cyber-security training and awareness programme covers topics such as phishing and the correct classification and handling of our information. We collaborate closely with governments, law enforcement and industry peers to understand and respond to new and emerging threats. Working with contractors Through documents that help bridge between our policies and those of our contractors, we define the way our safety management system co-exists with those of our contractors to manage risk on a site. For our contractors facing the most serious risks, we conduct quality, technical, health, safety and security audits before awarding contracts. Once they start work, we continue to monitor their safety performance. Our OMS includes requirements and practices for working with contractors. Our standard model contracts
include health, safety and security requirements. We expect and encourage our contractors and their employees to act in a way that is consistent with our code of conduct and take appropriate action if those expectations, or their contractual obligations, are not met. Our partners in joint arrangements« In joint arrangements where we are the operator, our OMS, code of conduct and other policies apply. We aim to report on aspects of our business where we are the operator – as we directly manage the performance of these operations. We monitor performance and how risk is managed in our joint arrangements, whether we are the operator or not. Where we are not the operator, our OMS is available as a reference point for bp businesses when engaging with operators and co-venturers. We have a group framework to assess and manage bp’s exposure related to safety, operational and bribery and corruption risk from our participation in
these types of arrangements. Where appropriate, we may seek to influence how risk is managed in arrangements where we are not the operator.
61 Strategic report bp Annual Report and Form 20-F 2020 Our values and code of conduct Our values of safety, respect, excellence, courage and one team represent the qualities and actions we wish to see in bp. They inform how we do business and the decisions we make. We use these values as part of our recruitment, promotion and individual performance management processes. Our code of conduct is based on our values and sets clear expectations for how we work at bp. It applies to all bp employees and members of the board. Employees,
contractors or other third parties who have a question about our code of conduct or see something that they feel is unethical or unsafe can discuss this with their managers, supporting teams, works councils (where relevant) or through OpenTalk, a confidential and anonymous helpline operated by an independent company. We received more than 1,600 concerns or enquiries through these channels in 2020 (2019 1,800). The most commonly raised concerns were related to the ‘Our people’ section of our code of conduct. The section addresses issues such as harassment, equal opportunity, and diversity and inclusion. We take steps to identify and correct areas of non-conformance and take disciplinary action where appropriate. In 2020 our businesses dismissed approximately 50 bp employees for non-conformance with our code of conduct or unethical behaviour (2019 82a). This excludes dismissals of contractors and vendors, and staff employed at our
retail service stations. Anti-bribery and corruption We operate in parts of the world where bribery and corruption present a high risk. We have a responsibility to our employees, our shareholders and the countries and communities in which we do business to be ethical and lawful in all our work. Our code of conduct explicitly prohibits engaging in bribery or corruption in any form. Our group-wide anti-bribery and corruption policy and procedures include measures and guidance to assess risks, understand relevant laws and report concerns. They apply to all bp-operated businesses. Tax transparency We comply with tax laws in a responsible manner, pay and report our taxes on time and have open and constructive conversations with stakeholders, including governments and tax authorities. And we contribute to initiatives that simplify and improve tax regimes to encourage investment and sustainable growth and support the energy transition. We are committed to
being transparent about our tax principles and the taxes we pay. We paid $3.3 billion in corporate income and production taxes to governments (2019 $6.9 billion). In 2020 we endorsed the B Team Responsible Tax Principles and we published Our tax report 2019. The report provides more detailed information on how we approach tax matters and the tax payments we make. New disclosures in our tax report include the total tax contribution for our global operations. This covers: all our business activities and details the taxes we pay directly to governments on our own behalf, along with taxes we collect and pay to governments on behalf of others; financial and tax data from our OECD country-by-country report, summary activities of bp subsidiaries by country and details of bp companies located in countries considered to be low tax jurisdictions. bp is a founding member
of the Extractive Industries Transparency Initiative (EITI), which supports the disclosure of payments made to and received by governments in relation to oil, gas and mining. Through EITI we work with governments, NGOs and international agencies to improve transparency. bp.com/tax We provide training to employees appropriate to the nature or location of their role. Around 7,700 employees completed anti-bribery and corruption training in 2020 (2019 ~11,000). We assess any exposure to bribery and corruption risk when working with suppliers and business partners. Where appropriate, we put in place a risk mitigation plan or we reject them if we conclude that risks are too high. We also conduct anti-bribery compliance audits on selected suppliers when contracts are in place. Many of our production & operations projects conduct supplier audits to assess their conformance
with our anti-bribery and corruption contractual requirements. We take corrective action with suppliers and business partners that fail to meet our expectations, which may include terminating contracts. In 2020 we issued 35 audit reports (2019 25). While our audit process was disrupted in 2020 due to the COVID-19 pandemic, we continued to engage suppliers and communicate our expectations for managing bribery and corruption risk on behalf of bp. For example, our customers & products business delivered a regional annual contractor forum digitally, to provide awareness of bribery and corruption risks. Political donations and activity We prohibit the use of bp funds or resources to support any political candidate or party. We recognize the rights of our employees to participate in the political process and these rights are governed by the applicable laws in
the countries where we operate. The way in which we interact with those governments depends on the legal and regulatory framework in each country. Our stance on political activity is defined in our code of conduct. In the US we provide administrative support for the bp employee political action committee (PAC), which is a non-partisan committee that encourages voluntary employee participation in the political process. All bp employee PAC contributions are reviewed for compliance with federal and state law and are publicly reported in accordance with US election laws. The PAC paused all contributions for six months beginning in January 2021. During this time the PAC will re-evaluate its criteria for candidate support. Business ethics and accountability a 2019 figure differs from the 2019 figure (74) reported in the bp Annual Report and Form 20-F 2019 to reflect backdated dismissal decisions (concerns where dismissals were not known or recorded until
after the 2019 report was published), heliport spot check dismissals and changes to dismissal decisions.
62 bp Annual Report and Form 20-F 2020 Sustainability continued TCFD index table Our expanded TCFD disclosures can be found on the following pages. TCFD recommended disclosure Where reported Governance Disclose the organization’s governance around climate-related issues and opportunities. a. Describe the board’s oversight of climate-related risks and opportunities. Page 52. b. Describe the management’s role in assessing and managing climate related risks and opportunities. Page 53. Strategy Disclose the actual and potential impacts
of climate-related risks and opportunities on the organization’s business, strategy and financial planning where such information is material. a. Describe the climate-related risks and opportunities the organization has identified over the short, medium, and long term. Pursuing a strategy that is consistent with the Paris goals, pages 26-27. Strategy – page 54. Risk factors, pages 67-70. b. Describe the impact of climate-related risks and opportunities on the organization’s businesses, strategy, and financial planning. Risk factors, pages 67-70 – description of principal risks. Strategy – page 54. c. Describe the resilience of the organization’s strategy, taking into consideration different climate-related scenarios, including a 2°C or lower scenario. Our strategy, page 15. Pursuing a strategy that is consistent with the Paris goals, pages 26-27. Strategy – page 54. Risk management Disclose
how the organization identifies, assesses and manages climate-related risks. a. Describe the organization’s processes for identifying and assessing climate-related risks. Risk management – pages 54-55. How we manage risk, pages 64-66. Risk factors – page 67. b. Describe the organization’s processes for managing climate-related risks. Risk management, pages 54-55. How we manage risk, pages 64-66. c. Describe how processes for identifying, assessing, and managing climate-related risks are integrated into the organization’s overall risk management. Risk management, pages 54-55. How we manage risk, pages 64-66. Risk factors – pages 67-70. Metrics and targets Disclose the metrics and targets used to assess and manage relevant climate-related risks and opportunities where such information is material. a. Disclose the metrics used by the organization to assess climate-related risks and opportunities in
line with its strategy and risk management process. Our strategic focus areas and metrics, pages 18 and 19. Our group-wide principal metrics and relevant targets – page 55. b. Disclose Scope 1, Scope 2, and, if appropriate, Scope 3 GHG emissions, and the related risks. GHG emissions data – pages 49-50. c. Describe the targets used by the organization to manage climate-related risks and opportunities and performance against targets. Our net zero targets and aims at a glance – pages 49-51. More information on our sustainability performance bp.com/sustainability Sustainability at bp More information on our sustainability reporting. Key environmental, social and governance dataa bp.com/ESGdata For our mapping to key sustainability frameworks and standards, including SASB and GRI, see bp.com/reportingcentre a Selected sustainability information
in the ESG datasheet was subject to limited assurance by Deloitte LLP in accordance with the International Standard for Assurance Engagements (“ISAE”) 3000 (Revised).
63 Strategic report bp Annual Report and Form 20-F 2020 Our stakeholders Section 172 statement In accordance with the requirements of section 172 of the Companies Act 2006 (‘the Act’), the directors consider that, during the financial year ended 31 December 2020, they have acted in a way that they consider, in good faith, would most likely promote the success of the
company for the benefit of its members as a whole, having regard to the likely consequences of any decision in the long term and the broader interests of other stakeholders, as required by the Act. See table on pages 82-83 for more information in support of this statement, including a description of the board’s activities during 2020. Employees Monitoring employee sentiment We use our ‘Pulse’ survey and weekly ‘Pulse Live’ surveys to gather feedback from employees, including their perceptions of work demands and leadership support. The employee engagement score is a key performance indicator for bp, see page 41. Investors Developing our new strategy, financial frame and investor proposition Our decision to introduce a new strategy, financial frame and investor proposition, including a new distribution policy, benefited from extensive dialogue with our major shareholders. ESG engagement We engage frequently
with our investors on environmental, social and governance (ESG) issues. This includes one-to-one conversations, participation at external events and group meetings, including with Climate Action 100+ representatives. bp week In response to feedback from investors and others, CEO Bernard Looney and his leadership team offered further insight into bp’s new strategy and sustainability frame during bp week – three consecutive virtual capital markets days held in September 2020. Keeping connected through webcasts CEO Bernard Looney hosted regular ‘Keeping Connected’ webcasts to discuss important topics with members of the leadership team and subject matter experts such as our partner Equinor’s EVP, New Energy Solutions, and our vice president health and wellbeing, Dr Richard Heron. The sessions included a live Q&A section where employees could ask questions, anonymously if desired, of the CEO and webcast
guests. See page 86 for more on how the board and senior management team engaged with stakeholders throughout the year. Society Our biodiversity position We developed our updated position with input and constructive challenge from international nature and conservation organizations and experts including Conservation International, Fauna & Flora International (FFI), UNESCO and IUCN. The position sets out new measures to help restore, maintain and enhance nature. In September we announced a five-year collaboration with FFI to help support the delivery of our new position, including our aim to achieve a net positive impact. Our human rights policy We updated our business and human rights policy in 2020 to address emerging human rights issues relevant to our industry, clarify our human rights commitments and communicate how bp’s approach to managing human rights impacts has advanced. The update was supported by consultations with a wide
range of NGOs, subject matter experts and investors. Responding to feedback When our ‘Pulse Live’ and Employee Assistance platforms showed increased anxiety in employees, our CEO Bernard Looney led a series of live webcasts, including one focused on reducing mental health stigma and encouraging employees to ask for help. We also increased the frequency of mental health awareness training for managers. Examples of engagement with other stakeholder groups Customers Collaboration with original equipment manufacturers such as Ford, Renault, JLR and Volvo on future technologies. Global customer brand tracking. Government and regulators Publication of Our tax report 2019 – see bp.com/tax. Government lobbying – we actively advocated for regional carbon pricing schemes in the US, provided input to the EU methane strategy and supported the UK government’s planned phase out of internal combustion engines. Partners
and suppliers Supplier workshops, including sessions focused on net zero, people and planet. University collaborations, including the Carbon Mitigation Initiative (CMI), an independent academic research programme based at Princeton University. Throughout bp we engage with a wide variety of stakeholders on a regular basis. This engagement informs our thinking and decision making. Some examples of our engagement in 2020 are set out below. How we engage with our stakeholders
64 bp Annual Report and Form 20-F 2020 How we manage risk How we manage risk bp manages, monitors and reports on the principal risks and uncertainties that can impact our ability to deliver our strategy.
These risks are described in the Risk factors on page 67. Our management systems, organizational structures, processes, standards, code of conduct and behaviours together form a system of internal control that governs how we conduct the business of bp and manage associated risks. bp’s risk management system bp’s risk management system and policy is designed to be a consistent and clear framework for managing and reporting risks from the group’s operations to management and to the board. The system seeks to avoid incidents and enhance business outcomes by allowing us to: Understand the risk environment, identify the specific risks and assess the potential exposure for bp. Determine how best to deal with these risks to manage overall potential exposure. Manage the identified risks in appropriate ways. Monitor and seek assurance of the effectiveness of the management of these risks and intervene for improvement where necessary. Report
up the management chain and to the board on a periodic basis on how significant risks are being managed, monitored, assured and the improvements that are being made. Business and strategic risk management – our businesses, integrators and enablers integrate risk management into key business processes such as strategy, planning, performance management, resource and capital allocation, and project appraisal. We do this by using a standard framework for collating risk data, assessing risk management activities, making further improvements and in connection with planning new activities. Oversight and governance – throughout the year management, the leadership team, the board and relevant committees provide oversight of how significant risks to bp are identified, assessed and managed. They help to ensure that risks are governed by relevant policies and are managed appropriately. Such oversight may include reviews of the outcomes of business
processes including strategy, planning and resource and capital allocation. bp’s group risk team analyses the group’s risk profile and maintains the group’s risk management system. Our internal audit team provides independent assurance to the chief executive and board as to whether the group’s system of internal control is adequately designed and operating effectively to respond appropriately to the risks that are significant to bp. Risk oversight and governance Key risk oversight and governance committees include the following: Our risk management activities Day-to-day risk management – management and staff at our facilities, assets, and within our businesses, integrators and enablers seek to identify and manage risk, promoting safe, compliant and reliable operations. bp requirements, which take into account applicable laws and regulations, underpin the practical plans developed to help reduce risk and deliver
safe, compliant and reliable operations as well as greater efficiency and sustainable financial results. Day-to-day risk management Identify, manage and report risks Business and strategic risk management Plan, manage performance and assure Oversight and governance Set policy and monitor principal risks Facilities, assets and operations Businesses, integrators and enablers Leadership team and enablers The board Leadership team and its committees Leadership team meeting – for oversight and for strategic and commercial risks. Group operations risk committee – for health, safety, security, environment and operations integrity risks. Group financial risk committee – for finance, treasury, trading and cyber risks. Group disclosure committee – for financial reporting risks. Group people and culture committee – for employee risks. Group ethics and compliance committee – for legal and regulatory compliance
and ethics risks. Resource commitment meeting – for investment decision risks. bp quarterly audit meeting – for assurance on the oversight of bp’s principal risks. Board and its committees bp board. Audit committee. Safety and sustainability committee. Remuneration committee. People and governance committee. For bp governance framework see page 88, Board activities see page 80, and committee reports see pages 92-102 and 105.
65 Strategic report bp Annual Report and Form 20-F 2020 Risk management processes We aim for a consistent basis of measuring risk to: Establish a common understanding of risks on a like-for-like basis, taking
into account potential impact and likelihood. Report risks and their management to the appropriate levels of the organization. Inform prioritization of specific risk management activities and resource allocation. Businesses, integrators and enablers review significant risks and associated risk management activities in alignment with key business processes to help enable key decisions to be risk informed. As part of bp’s annual planning process, the leadership team and board review the group’s principal risks and uncertainties and determine risks for particular oversight by the board and its committees. These may be updated during the year in response to changes in internal and external circumstances. Our risk profile The nature of our business operations is long term, resulting in many of our risks being enduring in nature. Nonetheless, risks can develop and evolve over time and their potential impact or likelihood may vary in response
to internal and external events. These may include emerging risks which are considered through existing processes, including bp’s risk management system, bp’s Energy Outlook, bp’s Technology Outlook and group strategic reviews. We identify longer-term strategic risks and high priority risks for particular oversight by the board and its various committees in the coming year. There can be no certainty that our risk management activities will mitigate or prevent these, or other risks, from occurring. Further details of the principal risks and uncertainties we face are set out in Risk factors on page 67. Risks for particular oversight by the board and its committees in 2021 The risks for particular oversight by the board and its committees in 2021 have been reviewed and are listed in this section. These may be updated throughout the year in response to changes in internal and external circumstances. The oversight and management of
other risks is undertaken in the normal course of business. In addition to the risks reviewed in 2020, climate-related risks remain a longer-term strategic risk. The impact of COVID-19 The spread of COVID-19 has caused a significant drop in the oil and gas prices and refining margins. bp’s future financial performance will be impacted by the extent and duration of the current market conditions and the effectiveness of the actions that it and others take, including its financial interventions. Our financial frame is designed to be robust to periods of low price, with flexibility to reduce cost and capital expenditure if required. We continue to assess the impact of COVID-19 on our staff and operations and have instigated appropriate mitigation plans. Climate-related risks Risks associated with climate change and the transition to a lower carbon economy impact many elements of our strategy and, as such, these risks are considered through key business
processes including the strategy, annual plan, capital allocation and investment decisions. The outputs of these key business processes are reviewed in line with the cadence of these activities. Further details are described in Climate change and the environment on page 52. Strategic and commercial risks Financial liquidity External market conditions can impact our financial performance. Supply and demand and the prices achieved for our products can be affected by a wide range of factors including political developments, consumer preferences for low carbon energy, global economic conditions and the influence of OPEC. We seek to manage this risk through bp’s diversified portfolio, our financial framework, liquidity stress testing, maintaining a significant cash buffer, regular reviews of market conditions and our planning and investment processes. See Prices and markets and Liquidity, financial capacity and financial, including credit, exposure on
page 67. Cyber security The targeted and indiscriminate threats to the security of our digital infrastructure and those of third parties continue to evolve rapidly and are increasingly prevalent across industries worldwide. In addition, the COVID-19 pandemic changed ways of working and introduced new phishing campaigns. We seek to manage this risk through a range of measures, which include cyber security standards, security protection tools, ongoing detection and monitoring of threats and testing of cyber response and recovery procedures. We collaborate closely with governments, law enforcement agencies and industry peers to understand and respond to new and emerging cyber threats. We build awareness with our staff, share information on incidents with leadership for continuous learning and conduct regular exercises including with the leadership team to test response and recovery procedures.
66
bp Annual Report and Form 20-F 2020 Geopolitical The diverse locations of our operations around the world expose us to a wide range of political developments and consequent changes to the economic and operating environment. Geopolitical risk is inherent to many regions in which we operate, and heightened political or social tensions or changes in key relationships could adversely affect the group. We seek to manage this risk through development and maintenance of relationships with governments and stakeholders and by becoming trusted partners in each country and region. In addition, we closely monitor events and implement risk mitigation plans where appropriate. Compliance and control risks Ethical misconduct and legal or regulatory non-compliance Ethical misconduct or breaches of applicable laws or regulations could damage our reputation, result in litigation, regulatory action and penalties, adversely affect results and shareholder value, and potentially
affect our licence to operate. Our code of conduct and our values and behaviours, applicable to all employees, are central to managing this risk. Additionally, we have various group requirements and training covering areas such as anti-bribery and corruption, anti-money laundering, competition/anti-trust law and international trade regulations. We seek to keep abreast of new regulations and legislation and plan our response to them. We offer an independent confidential helpline, OpenTalk, for employees, contractors and other third parties. Trading non-compliance In the normal course of business, we are subject to risks around our trading activities which could arise from shortcomings or failures in our systems, risk management methodology, internal control processes or employee conduct. We have specific operating standards and control processes to manage these risks, including guidelines specific to trading, and seek to monitor compliance through our dedicated
compliance teams. We also seek to maintain a positive and collaborative relationship with regulators and the industry at large. Safety and operational risks Process safety, personal safety and environmental risks The nature of the group’s operating activities exposes us to a wide range of significant health, safety and environmental risks such as incidents associated with releases of hydrocarbons when drilling wells, operating facilities and transporting hydrocarbons. Our operating management system« helps us manage these risks and drive performance improvements. It sets out the standards and requirements which govern key risk management activities such as inspection, maintenance, testing, business continuity and crisis response planning and competency development. In addition, we conduct our drilling activity through a wells organization in order to promote a consistent approach for designing, constructing and managing wells. Security
Hostile acts such as terrorism or piracy could harm our people and disrupt our operations. We monitor for emerging threats and vulnerabilities to manage our physical and information security. Our central security team provides guidance and support to our businesses through a network of regional security advisors who advise and conduct assurance activities with respect to the management of security risks affecting our people and operations. We continue to monitor threats globally and maintain disaster recovery, crisis and business continuity management plans. The impact of the UK’s exit from the EU We have been assessing the potential impact on bp of Brexit and the UK’s future global relationships and have not identified any significant risk to our business. The impact of reinventing bp on the organization Last year we announced that we are reinventing bp to help deliver our ambition. This significant reorganization includes a new structure,
a new leadership team, new ways of working and a reduction in the size of bp’s office- based workforce. Risks associated with these changes have been identified, assessed and are being managed. As part of our three lines of defence, our businesses, integrators and enablers are working to deliver clear accountabilities and the associated workload reduction. All individuals changing roles or leaving bp are required to complete a comprehensive management of change. Material risk management actions are being assured by internal audit. How we manage risk continued
67 Strategic report bp Annual Report and Form 20-F 2020 The risks discussed below, separately or
in combination, could have a material adverse effect on the implementation of our strategy, our business, financial performance, results of operations, cash flows, liquidity, prospects, shareholder value and returns and reputation. Strategic and commercial risks Prices and markets – our financial performance is impacted by fluctuating prices of oil, gas and refined products, technological change, exchange rate fluctuations, and the general macroeconomic outlook. Oil, gas and product prices are subject to international supply and demand and margins can be volatile. Political developments, increased supply from new oil and gas or alternative low carbon energy sources, technological change, global economic conditions, public health situations (including the continued impact of the COVID-19 pandemic or any future epidemic or pandemic) and the influence of OPEC can impact supply and demand and prices for our products. Decreases in oil, gas or product
prices could have an adverse effect on revenue, margins, profitability and cash flows. If significant or for a prolonged period, we may have to write down assets and re-assess the viability of certain projects, which may impact future cash flows, profit, capital expenditure, the ability to work within our financial frame and maintain our long-term investment programme. Conversely, an increase in oil, gas and product prices may not improve margin performance as there could be increased fiscal take, cost inflation and more onerous terms for access to resources. The profitability of our refining activities can be volatile, with periodic over-supply or supply tightness in regional markets and fluctuations in demand. Exchange rate fluctuations can create currency exposures and impact underlying costs and revenues. Crude oil prices are generally set in US dollars, while products vary in currency. Many of our major project« development costs are denominated
in local currencies, which may be subject to fluctuations against the US dollar. Access, renewal and reserves progression – inability to access, renew and progress upstream resources in a timely manner could adversely affect our long-term replacement of reserves. Focused renewal of our reserve base in line with our strategy depends on our ability to progress upstream resources from our existing portfolio and access new resource in our core areas, generating future opportunities for oil and natural gas production. Competition for access to investment opportunities, heightened political and economic risks where we operate, unsuccessful exploration activity, technical challenges and capital commitments may adversely affect our reserve replacement. This, and our ability to progress upstream resources at a level in line with our strategic outlook for hydrocarbon production, could impact our future production and financial performance. Major project delivery
– failure to invest in the best opportunities or deliver major projects successfully could adversely affect our financial performance. We face challenges in developing major projects, particularly in geographically and technically challenging areas. Poor investment choice, efficiency or delivery, or operational challenges at any major project that underpins production or production growth could adversely affect our financial performance. Geopolitical – exposure to a range of political developments and consequent changes to the operating and regulatory environment could cause business disruption. We operate and may seek new opportunities in countries, regions and cities where political, economic and social transition may take place. Political instability, changes to the regulatory environment or taxation, international trade disputes and barriers to free trade, international sanctions, expropriation or nationalization of property, civil
strife, strikes, insurrections, acts of terrorism, acts of war and public health situations (including the continued impact of the COVID-19 pandemic or any future epidemic or pandemic) may disrupt or curtail our operations or development activities. These may in turn cause production to decline, limit our ability to pursue new opportunities, affect the recoverability of our assets or cause us to incur additional costs, particularly due to the long-term nature of many of our projects and significant capital expenditure required. Events in or relating to Russia, including trade restrictions and other sanctions, could adversely impact our income and investment in or relating to Russia. Our ability to pursue business objectives and to recognize production and reserves relating to these investments could also be adversely impacted. Liquidity, financial capacity and financial, including credit, exposure – failure to work within our financial framework
could impact our ability to operate and result in financial loss. Failure to accurately forecast or work within our financial framework could impact our ability to operate and result in financial loss. Trade and other receivables, including overdue receivables, may not be recovered, divestments may not be successfully completed and a substantial and unexpected cash call or funding request could disrupt our financial framework or overwhelm our ability to meet our obligations. Risk factors
68 bp Annual Report and Form 20-F 2020 An event such as a significant operational incident, legal proceedings or a geopolitical event in an area where we have significant activities, could
reduce our financial liquidity and our credit ratings. Credit rating downgrades could potentially increase financing costs and limit access to financing or engagement in our trading activities on acceptable terms, which could put pressure on the group’s liquidity. bp’s credit rating downgrades could also trigger a requirement for the company to review its funding arrangements with the bp pension trustees and may cause other impacts on financial performance. In the event of extended constraints on our ability to obtain financing, we could be required to reduce capital expenditure or increase asset disposals in order to provide additional liquidity. See Liquidity and capital resources on page 306 and Financial statements – Note 29. Joint arrangements and contractors – varying levels of control over the standards, operations and compliance
of our partners, contractors and sub-contractors could result in legal liability and reputational damage. We conduct many of our activities through joint arrangements«, associates«or with contractors and sub-contractors where we may have limited influence and control over the performance of such operations. Our partners and contractors are responsible for the adequacy of the resources and capabilities they bring to a project. If these are found to be lacking, there may be financial, operational or safety exposures for bp. Should an incident occur in an operation that bp participates in, our partners and contractors may be unable or unwilling to fully compensate us against costs we may incur on their behalf or on behalf of the arrangement. Where we do not have operational control of a venture, we may still be pursued by regulators or claimants in the event of an incident. Digital infrastructure and cyber security –
breach or failure of our or third parties’ digital infrastructure or cyber security, including loss or misuse of sensitive information could damage our operations, increase costs and damage our reputation. The energy industry is subject to fast-evolving risks from cyber threat actors, including nation states, criminals, terrorists, hacktivists and insiders. A breach or failure of our or third parties’ digital infrastructure – including control systems – due to breaches of our cyber defences, or those of third parties, negligence, intentional misconduct or other reasons, could seriously disrupt our operations. This could result in the loss or misuse of data or sensitive information, injury to people, disruption to our business, harm to the environment or our assets, legal or regulatory breaches and legal liability. Furthermore, the rapid detection of attempts to gain unauthorized access to our digital infrastructure,
often through the use of sophisticated and co-ordinated means, is a challenge and any delay or failure to detect could compound these potential harms. These could result in significant costs including fines, cost of remediation or reputational consequences. Climate change and the transition to a lower carbon economy – developments in policy, law, regulation, technology and markets, including societal and investor sentiment, related to the issue of climate change could increase costs, constrain our operations and affect our business plans and financial performance. Laws, regulations, policies, obligations, government actions, social attitudes and customer preferences relating to climate change and the transition to a lower carbon economy, including the pace of change to any of these factors, and also the pace of the transition itself, could have adverse impacts on our business including on our access to and realization of competitive opportunities
in any of our strategic focus areas, a decline in demand for, or constraints on our ability to sell certain products, constraints on production and supply and access to new reserves, adverse litigation and regulatory or litigation outcomes, increased costs from compliance and increased provisions for environmental and legal liabilities. Investor preferences and sentiment are influenced by environmental, social and corporate governance (ESG) considerations including climate change and the transition to a lower carbon economy. Changes in those preferences and sentiment could affect our access to capital markets and our attractiveness to potential investors, potentially resulting in reduced access to financing, increased financing costs and impacts upon our business plans and financial performance. Technological improvements or innovations that support the transition to a lower carbon economy, and customer preferences or regulatory incentives that alter fuel
or power choices, could impact demand for oil and gas. Depending on the nature and speed of any such changes and our response, these changes could increase costs, reduce our profitability, reduce demand for certain products, limit our access to new opportunities, require us to write down certain assets or curtail or cease certain operations, and affect investor sentiment, our access to capital markets, our competitiveness and financial performance. Policy, legal regulatory, technological and market developments related to climate change could also affect future price assumptions used in the assessment of recoverability of asset carrying values including goodwill, the judgement as to whether there is continued intent to develop exploration and appraisal intangible assets, the timing of decommissioning of assets and the useful economic lives of assets used for the calculation of depreciation and amortization. See Financial statements – Note 1 and Climate
change and the environment on page 52. Risk factors continued
69 Strategic report bp Annual Report and Form 20-F 2020 Competition – inability to remain efficient, maintain a high-quality portfolio of assets, innovate and retain an appropriately skilled workforce could negatively impact delivery of our strategy in a highly competitive market. Our strategic progress and performance could be impeded if we are unable to control our development and operating costs and margins, if we fail to scale our businesses at pace, or to sustain, develop and operate a high- quality portfolio of assets efficiently. Furthermore, as we transition from an International Oil Company
to an Integrated Energy Company, we face an expanded and rapidly evolving range of competitors in the sectors in which we operate. We could be adversely affected if competitors offer superior terms for access rights or licences, or if our innovation in areas such as new low carbon technologies, digital, customer offer, exploration, production, refining, manufacturing or renewable energy lags those of our competitors. Our performance could also be negatively impacted if we fail to protect our intellectual property. Our industry faces increasing challenges to recruit and retain diverse, skilled and experienced talent. Successful recruitment, development and retention of specialist staff is essential to our plans. Crisis management and business continuity – failure to address an incident effectively could potentially disrupt our business. Our business activities could be disrupted if we do not respond, or are perceived not to respond, in an appropriate
manner to any major crisis or if we are not able to restore or replace critical operational capacity. Insurance – our insurance strategy could expose the group to material uninsured losses. bp generally purchases insurance only in situations where this is legally and contractually required. Some risks are insured with third parties and reinsured by group insurance companies. Uninsured losses could have a material adverse effect on our financial position, particularly if they arise at a time when we are facing material costs as a result of a significant operational event which could put pressure on our liquidity and cash flows. Safety and operational risks Process safety, personal safety, and environmental risks – exposure to a wide range of health, safety, security and environmental risks could cause harm to people, the environment and our assets and result in regulatory action, legal liability, business interruption, increased costs, damage
to our reputation and potentially denial of our licence to operate. Technical integrity failure, natural disasters, extreme weather or a change in its frequency or severity, human error and other adverse events or conditions, including breach of digital security, could lead to loss of containment of hydrocarbons or other hazardous materials. This could also lead to constrained availability of resources used in our operating activities, as well as fires, explosions or other personal and process safety incidents, including when drilling wells, operating facilities and those associated with transportation by road, sea or pipeline. There can be no certainty that our operating management systemor other policies and procedures will adequately identify all process safety, personal safety and environmental risks or that all our operating activities, including acquired businesses, will be conducted in conformance with these systems. See Safety on page
59. Such events or conditions, including a marine incident, or inability to provide safe environments for our workforce and the public while at our facilities, premises or during transportation, could lead to injuries, loss of life or environmental damage. As a result we could face regulatory action and legal liability, including penalties and remediation obligations, increased costs and potentially denial of our licence to operate. Our activities are sometimes conducted in hazardous, remote or environmentally sensitive locations, where the consequences of such events or conditions could be greater than in other locations. Drilling and production – challenging operational environments and other uncertainties could impact drilling and production activities. Our activities require high levels of investment and are sometimes conducted in challenging environments such as those prone to natural disasters and extreme weather, which heightens the risks
of technical integrity failure. The physical characteristics of an oil or natural gas field, and cost of drilling, completing or operating wells is often uncertain. We may be required to curtail, delay or cancel drilling operations or stop production because of a variety of factors, including unexpected drilling conditions, pressure or irregularities in geological formations, equipment failures or accidents, adverse weather conditions and compliance with governmental requirements. Security – hostile acts against our staff and activities could cause harm to people and disrupt our operations. Acts of terrorism, piracy, sabotage and similar activities directed against our operations and facilities, pipelines, transportation or digital infrastructure could cause harm to people and severely disrupt operations. Our activities could also be severely affected by conflict, civil strife or political unrest. Product quality – supplying customers with
off-specification products could damage our reputation, lead to regulatory action and legal liability, and impact our financial performance. Failure to meet product quality specifications could cause harm to people and the environment, damage our reputation, result in regulatory action and legal liability, and impact financial performance.
70 bp Annual Report and Form 20-F 2020 Risk factors continued Compliance and control risks Ethical misconduct and non-compliance – ethical misconduct or breaches of applicable laws by our businesses or our employees could be damaging to our reputation, and could result in litigation, regulatory action and penalties. Incidents
of ethical misconduct or non-compliance with applicable laws and regulations, including anti-bribery and corruption and anti-fraud laws, trade restrictions or other sanctions, could damage our reputation, and result in litigation, regulatory action, penalties and potentially affect our licence to operate. Regulation – changes in the law and regulation could increase costs, constrain our operations and affect our business plans and financial performance. Our businesses and operations are subject to the laws and regulations applicable in each country, state or other regional or local area in which they occur. These laws and regulations result in an often complex, uncertain and changing legal and regulatory environment for our global businesses and operations. Changes in laws or regulations, including how they are interpreted and enforced, can and does impact all aspects of our business. Royalties and taxes, particularly those applied to our hydrocarbon
activities, tend to be high compared with those imposed on similar commercial activities. In certain jurisdictions there is also a degree of uncertainty relating to tax law interpretation and changes. Governments may change their fiscal and regulatory frameworks in response to public pressure on finances, resulting in increased amounts payable to them or their agencies. Changes in law or regulation could increase the compliance and litigation risk and costs, reduce our profitability, reduce demand for or constrain our ability to sell certain products, limit our access to new opportunities, require us to divest or write down certain assets or curtail or cease certain operations, or affect the adequacy of our provisions for pensions, tax, decommissioning, environmental and legal liabilities. Changes in laws or regulations could result in the nationalization, expropriation, cancellation, non-renewal or renegotiation of our interests, assets and related rights. Potential
changes to pension or financial market regulation could also impact funding requirements of the group. Following the Gulf of Mexico oil spill, we may be subjected to a higher level of fines or penalties imposed in relation to any alleged breaches of laws or regulations, which could result in increased costs. See Regulation of the group’s business on page 321. Treasury and trading activities – ineffective oversight of treasury and trading activities could lead to business disruption, financial loss, regulatory intervention or damage to our reputation. We are subject to operational risk around our treasury and trading activities in financial and commodity markets, some of which are regulated. Failure to process, manage and monitor a large number of complex transactions across many markets and currencies while complying with all regulatory requirements could hinder profitable trading opportunities. There is a risk that a single trader or a
group of traders could act outside of our delegations and controls, leading to regulatory intervention and resulting in financial loss, fines and potentially damaging our reputation. See Financial statements – Note 29. Reporting – failure to accurately report our data could lead to regulatory action, legal liability and reputational damage. External reporting of financial and non-financial data, including reserves estimates, relies on the integrity of the control environment, our systems and people operating them. Failure to report data accurately and in compliance with applicable standards could result in regulatory action, legal liability and damage to our reputation. The Strategic report was approved by the board and signed on its behalf by Ben J. S. Mathews, company secretary, on 22 March 2021.
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Corporate governance bp Annual Report and Form 20-F 2020 Corporate governance Introduction from the chairman 72 Board of directors 74 Leadership team 78 Board activities 80 Decision making by the board 82 How the board has engaged with shareholders, the workforce and other stakeholders 86 Governance framework 88 Learning, development and induction 90 Board evaluation 91 People and governance committee 92 Audit committee 94 Safety and sustainability committee 100 Geopolitical committee 102 Directors’ remuneration report 103 Remuneration committee 105 Since 2017 when the partnership with bp began, Lightsource bp has more than doubled its global presence, from five to 14 countries. It’s also grown its development pipeline from 1.6 to 17GW.
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bp Annual Report and Form 20-F 2020 Introduction from the chairman 2020 tested bp’s governance processes like no other year. Board members, like many colleagues across bp, have achieved and learned a lot together through our new way of working – and there’s much that we will continue. I am grateful for the flexibility, commitment and clear- sightedness of my board colleagues in 2020 – it bodes well for the years ahead. Helge Lund Chairman New strategy As a board, our responsibilities include determining bp’s purpose and strategy, monitoring its culture and seeking assurance that these are aligned with our values. For bp, 2020 was a year in which we felt this responsibility especially keenly. With the board’s support, bp adopted a new purpose – reimagining energy for people and our planet, which aligns bp’s capabilities and aspirations with the needs of society. 2020
was also the year bp’s new CEO, Bernard Looney, commenced his role. As well as formally launching our new purpose, Bernard set out a net zero ambition, new strategy, financial frame and investor proposition. These actions were taken with the full support of the board following a process of careful debate, and the board is confident that they respect bp’s culture and values. The change that was immediately most consequential for many people within bp was a restructure that will see close to 10,000 colleagues leave bp. It was difficult saying goodbye to people who helped make our organization what it is today – and the board was united with the leadership team in determining that the process should be conducted fairly and respectfully. That process is now largely complete, and I believe, as does the board, that bp is now leaner, flatter and nimbler – better able to fulfil our new purpose, ambition and strategy. COVID
impact on working of the board Change on this scale would be challenging in any company at any time. So, I want to pay tribute to my board colleagues for their contribution during such a difficult period. It is to their credit that we very quickly adapted to a new way of working together – with our many meetings since March held entirely virtually. Indeed, the COVID-19 pandemic justified more regular meetings with bp’s leadership – so early in the pandemic we instituted weekly calls to keep abreast of bp’s response to the pandemic and how the team was taking account of the needs and expectations of all our stakeholders. Maintaining bp’s culture Since joining bp, I have always been impressed at the strength of the company’s culture – open, co-operative, collaborative and performance- focused. Rather
than weaken that culture, I believe that the pandemic has strengthened it further – and has proved its value. bp would not have achieved all it did in 2020 without such a strong culture. We have been careful that the changes introduced throughout the year are respectful of it, and consistent with bp’s values of safety, respect, excellence, courage and one team. Board composition In 2020 we welcomed Tushar Morzaria, Karen Richardson and Johannes Teyssen to the board. They each have skills, experience and a diverse mindset that is closely aligned to the strategic direction we have set for bp. We also said goodbye to friends who have served bp with distinction over many years – Nils Andersen, Brian Gilvary, Sir Ian Davis, Dame Alison Carnwath and, of course, Bob Dudley. bp has been fortunate to have them, and we will miss them. I was delighted that Paula Reynolds agreed to take over from Sir Ian Davis as senior independent
director following the AGM 2020, and that Melody Meyer was able to take over the important role of chairing the safety and sustainability committee after Nils Andersen stepped down from the board. Tushar Morzaria will take over as chair of the audit committee after the AGM in May, following an extensive handover from Brendan Nelson, who will then retire.
73 Corporate governance bp Annual Report and Form 20-F 2020 In the coming year, one of my priorities will be to ensure that the board remains at an appropriate size, with strong composition, and with diversity of both thought and skills in support of the strategic direction we have set. Diversity The process
of reinventing bp provided opportunities to enhance bp’s diversity in other ways, too. Though we have more to do in all areas, we have made particular progress on gender diversity at senior levels. In 2020, we increased female board representation from 42% to 45%; increased female executive committee representation from 15% to 31%; and met the Hampton-Alexander and Parker review targets for 2021. New governance framework To complement bp’s new strategic direction, we have introduced a new governance framework, covering bp’s board-level corporate governance and facilitating a stronger board focus on strategy, performance, people and governance, with the committees each playing a critical role in support. The emphasis on strategy and its execution is especially important – I believe it to be where the board can deliver most value at this time, encouraging and working closely with the leadership team as they drive forward
our strategic progress, safety, financial and operational performance. The governance framework redefines the committees’ roles. Our newly-titled safety and sustainability committee rightly gains an enhanced focus on sustainability, but with no let-up on our core and overriding priority – safety, while our people and governance committee gains an enhanced focus on our single most important asset – our people. These committees and the insights they provide to the board very much support its effectiveness. Conclusion 2020 tested bp’s governance processes like no other year. Board members, like many colleagues across bp, have achieved and learned a lot together through our new way of working – and there’s much that we will continue. I am grateful for the flexibility, commitment and clear-sightedness of my board colleagues in 2020 – it bodes well for the years ahead. Helge Lund, Chairman
22 March 2021 Compliance with the UK Corporate Governance Code Throughout 2020, bp applied the principles and complied with all the provisions of the 2018 UK Corporate Governance Code.
74 Board gender diversity 1. 2. 1. Male 2. Female 7 5 bp Annual Report and Form 20-F 2020 Board of directors As at 22 March 2021 Murray Auchincloss Chief financial officer Appointed 1 July 2020 Nationality Canadian Outside interests Board member of Aker BP ASA; Member of The 100 Group Main Committee Career summary Murray Auchincloss qualified as a chartered financial analyst in the US, leading on to a wide range of tax and financial roles, first for Amoco and then for bp after the two
organizations merged in 1998. Murray has worked in both the US and UK, in a range of roles including chief financial officer, Upstream, and chief financial officer, North Sea. He was commercial director for the North American Gas business and, as head of the chief executive’s office for three years, managed all aspects of that office. Skills and experience Murray’s financial expertise, experience and knowledge make him a trusted advisor and bp group leader. His broad experience of working across the group has provided him with deep insight into bp’s assets and businesses. Murray has a degree in commerce from the University of Calgary, Canada, and qualified as a chartered financial analyst at the University of West Virginia, US. His drive to modernize is improving bp’s financial teams, controlling costs and continuing to deliver transparent financial disclosures to investors and markets. Bernard Looney Chief executive
officer Appointed 5 February 2020 Nationality Irish Outside interests Fellow of the Royal Academy of Engineering; Fellow of the Energy Institute; Mentor for the FTSE 100 Cross-Company Mentoring Executive Programme; Non-executive director of Rosneft Career summary Bernard Looney was appointed chief executive officer in February 2020. He previously ran bp’s Upstream business from April 2016 and has been a member of the company’s executive management team since November 2010. As chief executive, Upstream, Bernard was responsible for bp’s oil and gas exploration, development and production activities worldwide. In this role, Bernard oversaw improvements in both process and personal safety performances, and production grew by 20%. He led access into new countries, high-graded the portfolio and created innovative new business models. In earlier Upstream
executive roles, he was responsible for all bp-operated oil and gas production worldwide and for all bp’s drilling and major project« activity. Bernard joined bp in 1991 as a drilling engineer and worked in operational roles in the North Sea, Vietnam and the Gulf of Mexico. Skills and experience Bernard has spent his career at bp and has demonstrated dynamic leadership and vision as he has progressed through various roles within bp. During his 10 years as a leader of Upstream, Bernard saw the segment through one of the most difficult periods in bp’s history, helping transform the organization into a safer, stronger and more resilient business. He was instrumental in a number of workforce-based initiatives to promote a diverse and inclusive environment. Bernard set out bp’s new strategy in 2020 and is guiding the company through its
transformation. Helge Lund Chairman Appointed Board: 26 July 2018; Chairman: 1 January 2019 Nationality Norwegian Outside interests Chairman of Novo Nordisk AS; Operating Advisor to Clayton Dubilier & Rice; Member of the Board of Trustees of the International Crisis Group; Member of the European Round Table of Industrialists Career summary Helge Lund was appointed chairman of the bp board on 1 January 2019. He served as chief executive of BG Group from 2015 to 2016, when it merged with Shell. He joined BG Group from Equinor (formerly Statoil) where he served as its president and chief executive officer for 10 years from 2004. Prior to Equinor, Helge was president and chief executive officer of the industrial conglomerate Aker Kvaerner, and has also held executive positions in the Norwegian industrial holding company, Aker RGI, and the former Norwegian power and industry company, Hafslund Nycomed. He worked as a consultant with McKinsey &
Company and served as a political advisor for the parliamentary group of the Conservative party in Norway. Prior to joining bp, he was a non-executive director of the oil service group Schlumberger from 2016 to 2018, and Nokia from 2011 to 2014. He served as a member of the United Nations Secretary-General’s Advisory Group on Sustainable Energy from 2011 to 2014. Skills and experience Helge’s distinguished career as a leader in the oil and gas industry and his open-minded and forward-looking approach is vital as he leads the board in its oversight of delivery of bp’s new strategy. He has deep industry knowledge and global business experience – not only in the oil and gas industry but also in pharmaceuticals, healthcare and construction. His innovative leadership of the board drives cohesion and a strong environment for constructive challenge and oversight as bp works to transform into an Integrated Energy Company. P
Committee membership key Chairman A Audit committee S Safety and sustainability committee R Remuneration committee P People and governance committee
75 Corporate governance Non executive directors’ tenure 1. 4. 2. 1. <1 year 2. 1–3 years 3 3 3. 4–6 years 2 4. 7+ years 2 3. Board nationality 1. 2. 1. UK 2. US 4 4 3. Non UK/US 4 3. bp Annual Report and Form 20-F 2020 Pamela Daley Independent non-executive director Appointed 26 July 2018 Nationality American Outside interests Director of BlackRock, Inc.; Director of SecureWorks, Inc. Career summary Pamela Daley joined General Electric Company (GE) in 1989 as tax counsel and held a
number of senior executive roles in the company, overseeing a wide range of corporate transactions and serving as senior vice president and senior advisor to the chairman in 2013, before retiring from GE. Pamela has served as a director of BlackRock since 2014 and of SecureWorks since 2016. She was a director of BG Group plc from 2014 to 2016 until its acquisition by Shell. She was a director of Patheon N.V. from 2016 to 2017 until its acquisition by Thermo Fisher and, prior to that, she was a partner at Morgan, Lewis & Bockius, a major US law firm, where she specialized in domestic and cross-border tax-oriented financings and commercial transactions. Skills and experience Pamela is a qualified lawyer with significant management insight obtained from previous senior positions held at companies that operate in highly regulated industries. Pamela has a wealth of
experience in global business and strategy gained from over 20 years in an executive role at GE. She also has experience in the UK oil and gas industry from her time served on the BG Group plc board. Pamela contributes important insight to the audit committee from her previous executive experience. In 2019, she joined the remuneration committee, where her understanding of employee and investor perspectives brings value. A R Professor Dame Ann Dowling Independent non-executive director Appointed 3 February 2012 Nationality British Outside interests Deputy vice-chancellor and emeritus professor of Mechanical Engineering at the University of Cambridge; Non-executive director of Smiths Group plc Career summary Professor Dame Ann Dowling is a deputy vice-chancellor and emeritus professor of mechanical engineering at the University of Cambridge where her research includes fluid mechanics, acoustics and combustion. She has held visiting posts at MIT and at
Caltech. Dame Ann is a fellow of the Royal Society and the Royal Academy of Engineering and a foreign associate of the US National Academy of Engineering, the Chinese Academy of Engineering and the French Academy of Sciences. She was an advisor at Rolls-Royce until 2015. Dame Ann was President of the Royal Academy of Engineering from September 2014 to 2019. In December 2015 she was appointed to the Order of Merit. Skills and experience Professor Dame Ann is an internationally respected leader in engineering research and the practical application of new technology in industry. Her contribution in these fields has been widely recognized by universities around the world. Her academic background provides valuable balance to the board and brings a different perspective to the safety and sustainability committee of which she is a member, particularly as developments in technology continue to accelerate. Her work in this area is supplemented by her chairing
the company’s technology advisory council. S Melody Meyer Independent non-executive director Appointed 17 May 2017 Nationality American Outside interests President of Melody Meyer Energy LLC; Director of the National Bureau of Asian Research; Trustee of Trinity University; Non-executive director of AbbVie Inc.; Non-executive director of NOV, Inc. Career summary Melody Meyer started her career in 1979 with Gulf Oil which later merged with Chevron Corporation, where she remained until her retirement in 2016. During her career with Chevron, Melody held several key leadership roles in global exploration and production, working on a number of international projects and operational assignments. Melody was the executive sponsor of the Chevron Women’s Network and continues as a mentor and advocate for the advancement of women in the industry. Melody is a C200
member, and has received several awards and accolades throughout her career including being recognized as a 2009 Trinity Distinguished Alumni, with the BioHouston Women in Science Award by Hart Energy as an Influential Woman in Energy in 2018, by Women Inc as 2018 Most Influential Corporate Board Directors, and Outstanding Director by 2020 Women on Boards. She serves on McKinsey Women in Energy Advisory Board and co-leads Women Corporate Directors in Houston. Skills and experience Melody brings a world-class operational perspective to the board, with a deep understanding of the factors influencing safe, efficient and commercially high-performing projects in a global organization. Her long and illustrious career in the oil and gas industry is predicated on a dedication to excellence, safety and performance improvements. She has expertise in the execution of major capital projects, technology, R&D, creation of businesses in new countries, strategic
and business planning, merger integration and safe and reliable operations. S R
76 bp Annual Report and Form 20-F 2020 Tushar Morzaria Independent non-executive director Appointed 1 September 2020 Nationality British Outside interests Group Finance Director of Barclays PLC; Member of The 100 Group Main Committee; Chair of the Sterling Risk Free Reference Rates Working Group Career summary Tushar Morzaria is a chartered accountant with over 25 years of strategic financial management, investment banking, operational and regulatory relations experience. He is currently Group Finance Director of Barclays PLC, the British universal banking and financial services company,
where he is a member of the Barclays board and executive committee. Tushar joined Barclays from JP Morgan in 2013, where he held various senior roles including the CFO of its Corporate & Investment Bank at the time of the merger of the investment bank and the wholesale treasury/security services business. Skills and experience Tushar’s position as Group Finance Director of Barclays PLC gives him a breadth of knowledge and insight into financial, tax, treasury, investor relations and strategic matters which will benefit bp as Tushar assumes the role of audit committee chair at the conclusion of bp’s annual general meeting on 12 May 2021. He has strong experience in delivering corporate change programmes while maintaining a focus on performance. Brendan Nelson Independent non-executive director Appointed 8 November 2010 Nationality British Outside interests Non-executive director of NatWest Markets plc Career summary Brendan Nelson
is a qualified chartered accountant. He was made a partner of KPMG in 1984. He served as a member of the UK board of KPMG from 2000 to 2006, subsequently being appointed vice chairman until his retirement in 2010. At KPMG International he held a number of senior positions including global chairman, banking and global chairman, financial services. Brendan has extensive financial experience, having been a non-executive director of The Royal Bank of Scotland Group p.l.c, where he also served as chairman of the group audit committee, until April 2019 and National Westminster Bank p.l.c. until December 2018. Brendan previously served as a member of the Financial Services Practitioner Panel for six years and was chairman of the audit committee of the Institute of Chartered Accountants of Scotland from 2005 to 2008 and later became President of the Institute of Chartered Accountants of Scotland from 2013 to 2014. Skills and experience Brendan has completed a
wide variety of audit, regulatory and due-diligence engagements over the course of his career. He played a significant role in the development of the profession’s approach to the audit of banks in the UK, with particular emphasis on establishing auditing standards. His role as a member of the Financial Reporting Review Panel enabled him to further contribute to the profession. This wide experience makes him ideally suited to chair the audit committee and to act as its financial expert. He brings related input from his role as the chair of the audit committee of a major bank. His specialism in the financial services industry allows him to contribute insight into the challenges faced by global businesses by regulatory frameworks. As previously announced, Brendan will retire from the board at the conclusion of bp’s annual general meeting on 12 May 2021. A P R Board of directors continued As at 22 March 2021 Karen Richardson Independent
non-executive director Appointed 1 January 2021 Nationality American Outside interests Director of Artius Acquisition Inc.; Director of Exponent Inc. Career summary Karen Richardson was Vice President of Sales at Netscape Communications Corporation from 1995 to 1998 before embarking on several senior executive roles at E.piphany from 1998 to 2003 and was Chief Executive Officer between 2003 and 2006. In 2011 she became a non-executive director of BT plc where she served for seven years and between 2016 and 2019 Karen was a director of Worldpay Inc. (Worldpay Group plc). Karen is currently a director of Artius Acquisition Inc., a special purpose acquisition company, and, since 2013, Exponent Inc., the engineering and scientific consulting company. Karen has a Bachelor of Science degree in Industrial Engineering from Stanford University and was awarded distinctions from the Stanford Industrial Engineering Department and the American Institute of Industrial
Engineers. Skills and experience Karen has over 30 years’ experience in the technology industry. She brings exceptional knowledge of digital, technology, cyber and IT security matters from her career working with innovative companies in Silicon Valley. As bp works to transform into an Integrated Energy Company, Karen has the skills, experience and diversity to further enhance the board’s ability to support and oversee the delivery of bp’s strategy. From the conclusion of the 2021 annual general meeting, Karen will become a member of the audit committee. A R
77 Corporate governance bp Annual Report and Form 20-F 2020 Sir John Sawers Independent
non-executive director Appointed 14 May 2015 Nationality British Outside interests Visiting Professor at King’s College London; Senior Adviser at Chatham House; Senior Fellow at the Royal United Services Institute; Global Adviser at the Council on Foreign Relations; Governor of the Ditchley Foundation; Director of the Bilderberg Association, UK; Executive Chairman of Newbridge Advisory Limited Career summary Sir John Sawers spent 36 years in public service in the UK, working on foreign policy, international security and intelligence. He was chief of the Secret Intelligence Service, MI6, from 2009 to 2014 and prior to that spent the bulk of his career in the Diplomatic Service, representing the British government around the world and leading negotiations at the UN, in the European Union and in the G8. After he left public service, Sir John was chairman and general partner of Macro Advisory Partners, a firm that advises clients on the intersection
of policy, politics and markets from February 2015 to May 2019. He then set up his own firm, Newbridge Advisory, to carry out similar work. Sir John was appointed Knight Grand Cross of the Order of St Michael and St George in the 2015 New Year Honours for services to national security. Skills and experience Sir John’s deep experience of international political and commercial matters is an asset to the board in navigating the geopolitical issues faced by a modern global company. Sir John’s unique skill set made him an ideal chair of bp’s geopolitical committee and he will continue to advise the board on these matters as the chair of the newly established geopolitical advisory council. Ben J S Mathews Company secretary Appointed 7 May 2019 Ben joined bp as a company secretary in May 2019. He is chairman of the Association of General Counsel and Company Secretaries of the FTSE 100 (GC100) and the co-chair of the Corporate Governance Council
of the Conference Board. Ben is also a Fellow of the Institute of Chartered Secretaries and Administrators. Former appointments include Group Company Secretary of HSBC Holdings plc and Rio Tinto plc. Dr Johannes Teyssen Independent non-executive director Appointed 1 January 2021 Nationality German Outside interests CEO and Chairman of the management board of E.ON SE (until 31 March 2021); Chairman of the Supervisory Board of Innogy SE.; Member of the Shareholders’ Committee of Nord Stream AG; Member of the Presidential Board of the Federation of German Industries Career summary Johannes began his professional career at VEBA AG in 1989. There he held a number of leadership positions across Legal Affairs and Key Account Sales. In 2000 VEBA became part of E.ON and in 2001 Johannes became a member of the Board of Management of the E.ON Group’s central management company in Munich. In 2004, he was also appointed to the Board of Management
of E.ON SE in Düsseldorf and later went on to become Vice Chairman in 2008 and CEO in 2010. He was President of Eurelectric from 2013 to 2015 and the World Energy Council’s Vice Chair responsible for Europe between 2006 to 2012. Johannes was a member of the Supervisory Board of Deutsche Bank AG between 2008 and 2018 and is currently a member of the Presidential Board of the Federation of German Industries and the Shareholders’ Committee of Nord Stream AG. Skills and experience Johannes brings exceptional experience and deep knowledge in the sector and its continuing transformation. His skill set further diversifies and strengthens the overall demographic and attributes of the board as a whole. His experience in the energy sector further enhances the board’s ability to support and oversee the delivery of bp’s new strategy. Johannes has a doctorate in law from the University of Göttingen. S P S Paula
Rosput Reynolds Senior independent director Appointed Board: 14 May 2015; Senior independent: 27 May 2020 Nationality American Outside interests Non-executive director and Chair Designate of National Grid plc; Non-executive director of General Electric Company; Chair of the Seattle Cancer Care Alliance Career summary Paula Rosput Reynolds commenced her energy career at Pacific Gas & Electric Corp in 1979 and spent over 25 years in the energy industry. She has held a number of executive positions during her career, including CEO of Duke Energy Power Services, Chairman, President and CEO of AGL Resources as well as Chairman and CEO of Safeco Corporation and Vice Chairman and Chief Restructuring Officer of AIG. Paula was a non-executive director of TransCanada Corporation and CBRE Group, Inc until May 2019, having been appointed in 2011 and 2016 respectively. Between 2011 and 2020 Paula was a non-executive director of BAE Systems PLC. Paula was awarded
the National Association of Corporate Directors (US) Lifetime Achievement Award in 2014. Skills and experience Paula has had a long career leading global companies in the energy and financial sectors. Her experience with international and US companies, including several restructuring processes and mergers, gives her insight into strategic and regulatory issues, which is an asset to the board. Her wider business experience and understanding of the views of investors are well suited to her being the chair of bp’s remuneration committee and senior independent director. R A P
78 bp Annual Report and Form 20-F 2020 The leadership team represents the principal executive
leadership of the bp group. Its members include bp’s executive directors (Bernard Looney and Murray Auchincloss whose biographies appear on page 74) and the senior management listed on these pages. Geoff Morrell EVP, communications & advocacy Leadership team tenure Appointed 1 July 2020 Nationality American Other board memberships None Career Geoff moved to London in 2017 to take over group communications and external affairs. He spent the prior six years leading bp America’s communications and government relations teams and was instrumental in rebuilding bp’s reputation following the Deepwater Horizon incident. Before joining bp, Geoff spent four years at the Pentagon, serving as chief spokesperson for the US Department of Defense under presidents Bush and Obama. He previously worked as a journalist, including as a White House correspondent for ABC News. William Lin EVP, regions, cities & solutions
Leadership team tenure Appointed 1 July 2020 Nationality American Other board memberships William is a non-executive director of Pan American Energy Group that operates in Argentina. Career William served as chief operating officer, Upstream regions before joining the leadership team. He has worked in bp for 25 years having spent most of his career working abroad in different countries. Previous senior roles include vice president – gas development and operations for Egypt, regional president for Asia Pacific and head of the group chief executive’s office. William managed the successful start-up of the Tangguh LNG facility during his time in Indonesia. Emma Delaney EVP, customers & products Leadership team tenure Appointed 1 July 2020 Emma previously served on bp’s executive team starting on 1 April 2020. Nationality Irish Other board memberships None Career Emma has spent 25 years working in bp, both in the Upstream
and the Downstream, most recently as interim chief executive officer Downstream from 1 April 2020 and prior to that as regional president for West Africa. She has held a variety of senior roles including Upstream chief financial officer for Asia Pacific and head of business development for gas value chains. In Downstream she held roles in retail and commercial fuels and planning. Leadership team As at 22 March 2021
79 Corporate governance bp Annual Report and Form 20-F 2020 Gordon Birrell EVP, production & operations Leadership team tenure Appointed 1 July 2020 Gordon previously served on bp’s executive team starting on 12 February 2020. Nationality British
Other board memberships None Career Before being appointed to his new role, Gordon was chief operating officer for production, transformation and carbon. In his bp career, Gordon has spent time in various leadership, technical, safety and operational risk roles, including four years as bp president Azerbaijan, Georgia and Turkey. Gordon is a Fellow of the UK Royal Academy of Engineering. Carol Howle EVP, trading & shipping Leadership team tenure Appointed 1 July 2020 Nationality British Other board memberships None Career Before taking on her current role, Carol ran bp Shipping and was the chief operating officer for IST oil. She has more than 20 years’ experience in the energy industry, many in integrated supply and trading. Previous roles include chief operating officer for natural gas liquids, regional leader of global oil Europe and finance. Carol also served as the head of the group chief executive’s office. David Eyton
EVP, innovation & engineering Leadership team tenure Appointed 1 July 2020 David previously served on bp’s executive team starting on 1 September 2018. Nationality British Other board memberships None Career David joined the executive team in 2018 as group head of technology. He joined bp in 1982 with a degree in engineering and has held several positions in petroleum engineering, commercial and business management. Previous senior roles include managing Wytch Farm, Trinidad Gas and Gulf of Mexico Deepwater Developments. He was awarded a CBE (Commander of the British Empire) by Queen Elizabeth II for his contributions to UK engineering and energy. David is a Fellow of the UK Royal Academy of Engineering. Kerry Dryburgh EVP, people & culture Leadership team tenure Appointed 1 July 2020 Nationality British Other board memberships Kerry sits as a non-executive director for the United Kingdom Strategic Command Career Kerry was previously
head of HR for the Upstream and has held a series of senior HR positions. She was a key driver behind the Upstream people transformation during 2015-2017. Kerry previously ran HR in bp’s Shipping, IST and corporate functions teams. She brings experience from other sectors in Europe and Asia, having worked at both BT and Honeywell before joining bp. Giulia Chierchia EVP, strategy & sustainability Leadership team tenure Appointed 1 July 2020 Nationality Belgian and Italian Other board memberships None Career Giulia joined bp from McKinsey, where she was a senior partner. She led the global downstream oil and gas practice and was a key member of the chemicals and electricity, power and natural gas practices. She begins this role with more than 10 years’ experience in the energy sector, including helping companies shape their strategies for the energy transition. Eric Nitcher EVP, legal Leadership team tenure Appointed 1 July
2020 Eric previously served on bp’s executive team starting on 1 January 2017. Nationality American Other board memberships None Career Eric sat on the executive team as group general counsel from 2017. He played a key role in forming the Russian joint venture TNK-BP and settling Deepwater Horizon claims. He began his career as a litigation and regulatory lawyer in Wichita, Kansas. He joined Amoco in 1990 and over the years has held a wide variety of roles, both in the US and elsewhere. Dev Sanyal EVP, gas & low carbon energy Leadership team tenure Appointed 1 July 2020 Dev previously served on bp’s executive team starting on 1 January 2012. Nationality British and Indian Other board memberships Dev is a non-executive director of Man Group plc, a member of the board of overseers of The Fletcher School of Law and Diplomacy at Tufts University and a member of the energy advisory board of the Government of India. Career Dev has
been a member of the executive team since 2011, firstly as executive vice president, strategy and regions, and since 2016, as chief executive alternative energy and executive vice president, regions. Dev joined bp in 1989 and has worked in London, Athens, Istanbul, Vienna and Dubai across various segments. Previous senior roles include CEO of bp Eastern Mediterranean, CEO of Air bp and group treasurer. He played a key role in bp navigating its way through the aftermath of the 2010 Deepwater Horizon incident.
80 bp Annual Report and Form 20-F 2020 Corporate governance Board activities Role of the board bp’s success is dependent upon effective and entrepreneurial leadership
by the board, establishing its purpose, strategy and values and doing so within a framework of prudent and effective controls, which enable risks to be assessed and managed. The board is responsible to bp’s owners for promoting the long-term sustainable success of the company, generating value for its shareholders, while having regard to its other stakeholders, the impact of its operations on the communities within which it operates, and the environment. Primary tasks of the board in 2020 included Defining and establishing a new purpose and strategy, while assessing and monitoring whether they were consistent with bp’s culture and values. In light of the significant operational challenges presented by the COVID-19 pandemic, establishing a rhythm of board meetings to ensure that the leadership team was supported, providing guidance to the CEO to ensure
that shareholder and other stakeholder interests were taken into account, while maintaining safe and reliable operations. Monitoring the activities and performance of bp’s leadership team, obtaining assurance about the delivery of 2025 and 2030 targets and aims and the sustainability frame within which they operate. Designing and establishing the board’s new corporate governance framework, including the delegations of authority under which it operates. Assessing and monitoring the principal risks and emerging risks of bp, having considered feedback from the committees of the board. Ways of working New ways of working were put in place during 2020 alongside the changes to the design of the board’s corporate governance framework. Meeting agendas were structured along four distinct pillars: strategy, performance, people, and governance, with the overarching focus being on the development of bp’s new strategy in support
of its transition to an Integrated Energy Company. The board and its committees met regularly during the year, as well as on an ad hoc basis, as required by business needs. Attendance is shown in the table on page 84. Although the board and its committees were able to hold physical meetings in the early part of the year, once COVID-19-related restrictions and controls were introduced, most meetings took place virtually. Throughout the year, the board and its committees continued to engage effectively through the use of technology. Key areas covered during 2020 under each of these pillars are set out on the next page.
81 Corporate governance bp Annual Report and Form
20-F 2020 Strategy During 2020 the board worked closely with the incoming chief executive officer (CEO) and his leadership team, establishing a new purpose and strategy for bp. bp’s purpose is to reimagine energy for people and our planet, with an ambition to become a net zero company by 2050 or sooner, and to help the world get to net zero. This new purpose recognizes: The world is on an unsustainable path – its carbon budget is running out. Energy markets have begun to shift towards low carbon and renewables. Oil and gas produced safely and efficiently will continue to perform a vital role for the world and our business, but over the longer term, demand for both oil and gas will be challenged. bp can contribute to the energy transition the world wants and needs and create value in doing so. The delivery and execution of the strategy that supports this new purpose is made possible through a resilient financial framework, including a
new approach to capital allocation. In 2020 the board determined a new distribution policy, which will support us in facing an increasingly uncertain world, allow us to strengthen the balance sheet, invest in our resilient and valuable hydrocarbons business, and invest adequately into the energy transition. A new distribution policy was approved by the board, comprising a reset and resilient dividend and a firm share buyback commitment, see page 22. Associated with the new strategy, the board also agreed a number of tactical divestments, including the disposal of its petrochemicals business. Alongside this, new business opportunities were progressed, for example the formation of a strategic partnership with Equinor, to develop offshore wind energy in the US, see page 21. Against the backdrop of the board’s activities during 2020 described in this section, the table on pages 82 and 83 sets out some examples of board decision making in 2020
and how the directors have performed their duty under Section 172. Performance The board reviewed project, operational and safety performance throughout the year, as well as the latest view on full-year delivery against plan and the implications for the group’s scorecard measures. Equally, in light of the challenging macro-economic environment facing the sector, the company’s financial performance, liquidity, credit position and associated financial risks were closely and regularly monitored by the board. In this way and through the regular interactions that were taking place during the year, the board was able to satisfy itself that bp was performing while transforming. Reports supplementing the role played by the board included: CEO and chief financial officer (CFO) reports. Group financial outlook. The annual effectiveness of investment review. Quarterly
and full-year results. Shareholder distributions. The annual plan and associated capital allocation commitments. On risk oversight, the board, assisted by its committees, also regularly reviewed its principal and emerging risks, including the process through which they are identified, evaluated and managed. Linked to this, the high-priority risks were reviewed in 2020, giving the directors the chance to seek assurance as to how those risks were prioritized and being managed. On internal controls, the board also assessed the effectiveness of the group’s system of internal control and risk management as part of the process through which it reviews and, ultimately, approves the bp Annual Report and Form 20-F. No specific areas of significant deterioration were identified in this assessment. The board concluded that the group’s system of internal control continued to be resilient. The board also concluded that the overall design of the
group’s system of internal control generally meets external expectations of components to be included in internal control frameworks. In arriving at these conclusions, the board took into account reports from group risk and internal audit, as well as reviews undertaken by the board and its committees during the year. In conducting reviews during the year, the board and its committees considered the impact of remote working on the control environment, among other key factors. For more information on bp’s system of risk management see How we manage risk on page 64. People The board, through the former nomination and governance committee, continued to focus on reviewing its own composition, skills, experience and diversity, as well as that of the bp leadership team. Ultimately, new board appointments were made during the year, most notably with the retirement of the CEO, Bob Dudley, and CFO, Brian Gilvary, succeeded by Bernard Looney and
Murray Auchincloss, respectively. Tushar Morzaria was appointed to the board and its audit committee with effect from September 2020. Karen Richardson and Dr Johannes Teyssen were appointed to the board with effect from 1 January 2021. Johannes was also appointed to the safety and sustainability committee with effect from the same date. A new leadership team under the CEO came into being on 1 July 2020. Through the new people and governance committee, the process for executive succession planning, talent management and development is being redesigned. People insights – particularly the reinvention of bp and its impact on the organization – were presented to the board and this committee by the CEO and EVP, people & culture, providing information on matters relating to people strategy, employee engagement, diversity and people processes and policies. To help inform board discussions and decisions, board members also engaged
directly with the workforce in structured events, see page 87. Governance The board established a new corporate governance framework, which is more closely aligned with bp’s new purpose and also reinforces the effectiveness of the internal control framework. For more information on the new corporate governance framework see page 88.
82 bp Annual Report and Form 20-F 2020 Corporate governance continued Decision making by the board As part of the wider board corporate governance redesign, the board reviewed the delegation of authority, in part reflecting the need to ensure that it remained appropriate in light of bp’s new strategy, and the 2025
and 2030 targets and aims. The board’s new ways of working are explained on page 80 including certain matters that under the new corporate governance framework are reserved for the board as set out in its new terms of reference. The execution of company strategy is undertaken by the CEO’s leadership team, under the day-to-day authority for the management of the company delegated to the CEO. Reflecting its governance responsibilities, the board satisfies itself that the CEO and the leadership team’s actions are in keeping with the direction it sets through receipt of management reports at each board meeting. Section 172 factor Key examples Page The likely consequences of any decision in the long term. Reinventing bp: Our strategy 15 Interests of employees. How the board has engaged with shareholders, the workforce and other stakeholders
Sustainability: People and society 86 57 Fostering the company's business relationships with suppliers, customers and others. How we engage with our stakeholders Sustainability: Business ethics and accountability 63 61 Impact of operations on the community and the environment. Managing our environmental impacts Sustainability: Safety 57 59-60 Maintaining a reputation for high standards of business conduct. Role of the board Sustainability: Business ethics and accountability 80 61 Acting fairly between members of the company. How the board has engaged with shareholders, the workforce and other stakeholders 86 More information on how the board had regard to the Section 172 factors Issue faced and decision taken Section 172(1)a) to (f) matters considered, including stakeholder group(s) affected
and feedback received How the board had regard to the feedback in its decision making Establishing a new purpose and strategy for bp The board approved a new purpose for bp – reimagining energy for people and our planet – and a strategy to transition to an Integrated Energy Company and to meet the net zero ambition set out alongside bp’s purpose. Workforce In town halls and leadership meetings employees wanted to know how bp could do more to step up to the climate challenge and help society deal with these issues. It became clear that employees were seeking even stronger commitments to the climate change agenda by the company. Community and environment We consulted with communities, NGOs, academics and industry associations – even bringing some of bp’s harshest critics into discussions about the future of the
company, about environment, social and governance matters and the issues facing the world, drawing on their external expertise, input and challenge. Investors We talked with investors about their expectations of bp and heard of their desire for bp to continue to deliver operational excellence, to drive higher returns but also to set out a clear medium to long-term vision for a sustainable bp business in light of the energy transition. Fostering business relationships We received feedback from customers via the bp leadership team, conveying the importance of being able to react rapidly to changing demand. All the elements highlighted in Section 172 were central to the discussions as the board evaluated the purpose and strategy options – what are bp’s beliefs and what does bp want to be? The discussions encompassed bp’s role with respect to its shareholders, employees and society. It considered the value creation opportunities
and the importance of leaning into the changing needs of customer demand for convenience and society’s demand for renewables and lower carbon energy. The change in purpose and strategy reflects bp’s people’s belief that we can create long-term value by helping solve one of society’s biggest problems – climate change. The decision was made with the long-term future and sustainability of bp in mind with clear 2025 targets, 2030 aims and a 2050 goal. Reinvent bp The board approved a reorganization of bp, retiring the existing model and replacing it with one that is more focused, more integrated and faces the energy transition head on. The reorganization will ultimately see around 10,000 employees leave bp. The board considered the importance of skills evaluation to the delivery of cost reduction and the wider long-term strategic delivery of bp’s aims. They heard feedback from the CEO’s ‘Keeping
Connected’ webcasts with the workforce together with responses to bp’s ‘Pulse’ surveys. Considerations The wider society context following the impact of COVID-19 and the wider oil industry job losses. The importance of putting the safety of employees first. Companies should try to provide job assurance and consider the mental health impact of job insecurity. bp’s reputation for high standards of conduct and the importance of honesty, fairness, and respect in the process. The board supported the reinvention of bp, with the associated headcount reduction that this implied. Given the feedback received, although the board considered it was the right decision to go ahead, they sought assurances from the executive that: The redundancy process was fair, transparent and objective with an environment of honesty, trust and co-operation that put the care and wellbeing of our people at the heart of the process. The
reduction in the workforce was conducted in a manner which protected bp’s safe and reliable operations. Support for the life transition that redundancy brings is offered to the relevant employees. Discretionary enhanced redundancy terms could be offered. Financial frame and distribution policy The board approved a new and resilient financial framework, including a coherent approach to capital allocation and a new distribution policy. In considering the proposed financial frame and distribution policy, the board had regard to: The resilience of bp’s balance sheet for the long term. Delivering sustainable value to shareholders. The need for bp to invest adequately in the energy transition and low carbon, to support the new ambition and strategy. In approving the new distribution policy the directors reflected that there may be some change in bp’s investor base as some investors focus more on the short-term direct return that
the dividend provides. After considering all the various factors, the board concluded that a resilient dividend intended to remain fixed at 5.25 cents per ordinary share per quarter (subject to the board’s decision each quarter), with a commitment to return at least 60% of surplus cash« to shareholders through share buybacks (having reached $35 billion net debt« and subject to maintaining a strong investment grade credit rating), was in the best interest of the company, its shareholders as a whole and other stakeholder groups, as it enabled bp to offer sustainable value with increased investment in low carbon and non-oil and gas ventures. Matters reserved for the board and section 172 The board delegates authority for the executive management of bp to the chief executive officer, subject to defined limits. Ultimately, the board retains responsibility
for – and regularly monitors – the execution of this delegation of authority, taking action to update it as required.
83 Corporate governance bp Annual Report and Form 20-F 2020 Issue faced and decision taken Section 172(1)a) to (f) matters considered, including stakeholder group(s) affected and feedback received How the board had regard to the feedback in its decision making Establishing a new purpose and strategy for bp The board approved a new purpose for bp – reimagining energy for people and our planet – and a strategy to transition to an Integrated Energy Company and to meet the net zero ambition set out alongside bp’s
purpose. Workforce In town halls and leadership meetings employees wanted to know how bp could do more to step up to the climate challenge and help society deal with these issues. It became clear that employees were seeking even stronger commitments to the climate change agenda by the company. Community and environment We consulted with communities, NGOs, academics and industry associations – even bringing some of bp’s harshest critics into discussions about the future of the company, about environment, social and governance matters and the issues facing the world, drawing on their external expertise, input and challenge. Investors We talked with investors about their expectations of bp and heard of their desire for bp to continue to deliver operational excellence, to drive
higher returns but also to set out a clear medium to long-term vision for a sustainable bp business in light of the energy transition. Fostering business relationships We received feedback from customers via the bp leadership team, conveying the importance of being able to react rapidly to changing demand. All the elements highlighted in Section 172 were central to the discussions as the board evaluated the purpose and strategy options – what are bp’s beliefs and what does bp want to be? The discussions encompassed bp’s role with respect to its shareholders, employees and society. It considered the value creation opportunities and the importance of leaning into the changing needs of customer demand for convenience and society’s demand for renewables and lower carbon energy. The change in purpose and strategy reflects bp’s people’s belief that we can create long-term value by helping solve one of society’s
biggest problems – climate change. The decision was made with the long-term future and sustainability of bp in mind with clear 2025 targets, 2030 aims and a 2050 goal. Reinvent bp The board approved a reorganization of bp, retiring the existing model and replacing it with one that is more focused, more integrated and faces the energy transition head on. The reorganization will ultimately see around 10,000 employees leave bp. The board considered the importance of skills evaluation to the delivery of cost reduction and the wider long-term strategic delivery of bp’s aims. They heard feedback from the CEO’s ‘Keeping Connected’ webcasts with the workforce together with responses to bp’s ‘Pulse’ surveys. Considerations The wider society context following the impact of COVID-19 and the wider oil industry job losses. The importance of putting the safety of employees first. Companies
should try to provide job assurance and consider the mental health impact of job insecurity. bp’s reputation for high standards of conduct and the importance of honesty, fairness, and respect in the process. The board supported the reinvention of bp, with the associated headcount reduction that this implied. Given the feedback received, although the board considered it was the right decision to go ahead, they sought assurances from the executive that: The redundancy process was fair, transparent and objective with an environment of honesty, trust and co-operation that put the care and wellbeing of our people at the heart of the process. The reduction in the workforce was conducted in a manner which protected bp’s safe and reliable operations. Support for the life transition that redundancy brings is offered to the relevant employees. Discretionary enhanced redundancy terms could be offered. Financial frame and distribution policy The
board approved a new and resilient financial framework, including a coherent approach to capital allocation and a new distribution policy. In considering the proposed financial frame and distribution policy, the board had regard to: The resilience of bp’s balance sheet for the long term. Delivering sustainable value to shareholders. The need for bp to invest adequately in the energy transition and low carbon, to support the new ambition and strategy. In approving the new distribution policy the directors reflected that there may be some change in bp’s investor base as some investors focus more on the short-term direct return that the dividend provides. After considering all the various factors, the board concluded that a resilient dividend intended to remain fixed at 5.25 cents per ordinary share per quarter (subject to the board’s decision each quarter), with a commitment to return at least 60% of surplus cash«
to shareholders through share buybacks (having reached $35 billion net debt« and subject to maintaining a strong investment grade credit rating), was in the best interest of the company, its shareholders as a whole and other stakeholder groups, as it enabled bp to offer sustainable value with increased investment in low carbon and non-oil and gas ventures. In the context of the board’s activities during 2020, the table below sets out some examples of board decision making in 2020 and how the directors have performed their duty under Section 172.
84 bp Annual Report
and Form 20-F 2020 Corporate governance continued Independence Non-executive directors (NEDs) are expected to exercise independent judgement and to be free from any business or other relationship that could materially interfere with it. This independence is crucial in bringing constructive challenge to the CEO and the leadership team at board meetings, while providing support and guidance to promote meaningful discussion and, ultimately, informed and effective decision making. The board regularly reviews the independence of its NEDs, as advised by the company secretary, and takes action to identify and manage conflicts of interests, including those that may arise from significant shareholdings. This process helps to ensure that the influence of third parties does not compromise or override independent judgement. Directors are required to provide sufficient information
to allow the board to evaluate their independence prior to and following their appointment. As a consequence of regular reviews throughout the year, the board has satisfied itself that there were no matters giving rise to any conflict of interests or which compromised the independence of the NEDs. It has therefore concluded that all bp NEDs are independent. Professor Dame Ann Dowling continues to serve on the board notwithstanding that she has served beyond nine years as a NED. Following careful consideration, the board believes that Ann continues to provide constructive challenge and robust scrutiny of matters that come before the board and the committee on which she serves. She has only served with the current executive directors for a year and the overall average tenure of the board is below the FTSE 100 average. In addition, in 2018 the board undertook significant refreshment of its composition. Accordingly, the board is satisfied that Ann continues
to demonstrate the qualities of independence in carrying out her duties. Appointment and time commitment The chairman, senior independent director and other NEDs each have letters of appointment and do not serve, nor are they employed, in any executive capacity. There is no fixed term limit on a director’s service; however, in line with good governance practice, bp proposes all directors for annual re-election by shareholders. Unlike the chairman’s letter of appointment, the NEDs’ letters of appointment do not set a fixed time commitment. NEDs are expected to allocate appropriate time to effectively discharge their duties. The time required of NEDs fluctuates depending on the demands of bp business and other events. The COVID-19 pandemic, as well as the oversight by the board of the energy transition and associated workload, required the NEDs to spend considerably more time fulfilling their responsibilities towards bp
during 2020, than in previous years. This included NEDs dedicating additional time through regular calls with the leadership team to remain informed and help guide the executive through unprecedented times. The NEDs’ external time commitments are regularly reviewed, ensuring that, even in the exceptional circumstances of a global pandemic, the NEDs are able to allocate appropriate time to bp. The review process is managed by the company secretary, considering NEDs’ outside appointments and commitments, including relevant factors such as complexity of company and industry, in particular highly regulated sectors, and issues impacting these other companies. The board has concluded that, notwithstanding the NEDs’ other appointments, they are each able to dedicate sufficient time to fulfil their bp duties. Executive directors are normally
permitted to take up one board appointment at an external company, subject to the agreement of the chairman and after consultation with the company secretary. Bernard Looney and Murray Auchincloss each hold one non-executive directorship, shown on page 74. Prior to retiring from the board in June 2020, Brian Gilvary undertook a role as NED of Barclays PLC, in addition to his NED role with L’Air Liquide S.A.. Following consideration, it was concluded that Brian’s two external appointments were unlikely to be detrimental to his ability to perform his duties as outgoing CFO. Diversity At a time of significant change across the sector, and with bp transitioning to become an Integrated Energy Company, diversity of thought is as important as ever. Our purpose, to reimagine energy for people and our planet, can only be achieved through collaboration, innovation
and constructive challenge that derives from having a diverse and inclusive workplace. The board understands and advocates that better decisions and outcomes are achieved when different people, with differences of opinions, from different backgrounds, come together with a common ambition. We recognize that diversity can take many forms, whether it be gender, social or ethnic backgrounds, personal identities, age, religion, physical abilities and more. All of which promote diversity of thought and reduce the risk of group think. The board has, and continues to have, regard to all these forms of diversity in respect of its processes including both its appointments and succession plans. The board and leadership team believe in leading by example and are pleased to have met the Hampton-Alexander and Parker review targets for 2021. At the end of 2020 the board comprised five female directors, representing 45% of the board (2019 42%, 2018 35%). Karen
Richardson and Johannes Teyssen joined the board on 1 January 2021. Dame Alison Carnwath stepped down from the board on 14 January 2021. As previously announced, Brendan Nelson will be stepping down from the board at the conclusion of the 2021 AGM. The board is pleased that Tushar Morzaria, a Ugandan-born British national, joined in September 2020. He will succeed Brendan Nelson as audit committee chair following the 2021 AGM. Our senior management, as defined by the Corporate Governance Code 2018, and their direct reports comprise 43% women (2019 38%) and 25% Black, Asian and minority ethnic (BAME) individuals (2019 18%). While bp continues to benefit from the wide array of perspective and vision in decision-making processes and the company culture continues to strengthen through mitigation of group think, bp will continue to strive for increased diversity across
its workforce, leadership team and board. For more information on our workforce diversity and inclusion see page 57.
85 Corporate governance bp Annual Report and Form 20-F 2020 Attendance Board Audit committee Safety and sustainability committee Remuneration committee Geopolitical committee People and Governance committee A B A B A B A B A B A B Non-executive directors Helge Lund 10• 10• 7• 7• Nils Andersen 3 2 2 2 4 4 1 1 3 3 Dame Alison Carnwath 10 10 10 10 Pamela Daley 10 9 10 9 9 7 Sir Ian Davis 10 9 9 7 3 2 7 7 Professor Dame Ann Dowling 10 9 6 6 Melody Meyer 10 10 6• 6• 5 5 3 3 Tushar Morzaria 3 3
3 3 Brendan Nelson 10 10 10• 10• 9 8 7 6 Paula Reynolds 10 10 10 10 9• 9• 7 7 Sir John Sawers 10 10 6 6 3• 3• 7 7 Executive directors Murray Auchincloss 5 5 Bob Dudley 2 2 Brian Gilvary 5 5 Bernard Looney 8 8 A Possible meetings B Attended meetings • Chair of board/committee
86 bp Annual Report and Form 20-F 2020 Corporate governance continued How the board has engaged with shareholders, the workforce and other stakeholders Retail investors In May we held our annual event for retail investors in conjunction with the UK Shareholders’ Association (UKSA) and the UK Individual Shareholders Society.
For the first time this event was held virtually. The chairman, company secretary and head of investor relations gave presentations on bp’s annual results, strategy and the work of the board. Shareholders’ questions were primarily focused on bp’s response to the COVID-19 pandemic, bp’s sustainability strategy and financial performance. AGM In common with the practice adopted by many UK quoted companies, the 2020 AGM was held as a ‘closed’ meeting, with a minimum quorum present, in line with government rules at the time. Shareholders were invited to submit questions to the board before the meeting, all of which were addressed, and the event was broadcast live via webcast on bp.com. As expected, voting levels saw a slight decrease with the pandemic and stay-at-home orders disrupting shareholder voting. The overall turnout was 62.1% of the total voting rights, including votes cast as withheld,
compared to 67.1% in 2019 and 67.3% in 2018. All resolutions passed at the meeting in line with the board’s recommendations. At the date of this report, measures put in place by the UK government in response to the COVID-19 pandemic preclude bp from holding an AGM in person. In these exceptional circumstances, bp’s 2021 AGM is planned to be a hybrid meeting. Shareholders will not be permitted to attend the meeting in person, but will be able to participate via bp’s electronic meeting platform. Institutional investors We regularly engage with our institutional shareholders through an active investor relations programme. COVID-19 has meant that this engagement had to move online for the majority of 2020. The pinnacle of this virtual engagement was bp week in September 2020, led by Bernard Looney and members of his leadership team. The team innovatively engaged with shareholders giving detailed insights into bp’s
new strategy and the 2025 and 2030 targets and aims. This engagement was also deliberately structured to allow for the increasingly important ESG constituency to be consulted in determining the targets and aims, including the overlay of the new sustainability frame in support of the new strategy. The board receives feedback from shareholders in many ways, particularly through the chairman and leadership team who meet with investors throughout the year. Numerous one-to-one meetings with major institutional investors and proxy advisory groups were hosted by the chairman in 2020. These engagements generated much insightful feedback which was shared with other board members and committees with due regard being given to these views. A similar programme of engagement on matters relating to the 2020 directors’ remuneration policy that was approved by shareholders at the AGM was undertaken during the year, led by the chair of the remuneration committee
and senior independent director, Paula Reynolds. More details about this engagement are set out in the 2020 directors’ remuneration report on page 103. The board will continue to monitor developments in UK government guidance relating to the COVID-19 situation. If circumstances change materially before the date of the AGM, the board may decide to adapt proposed arrangements. Shareholder engagement cycle 2020 Q1 Fourth quarter and full-year 2019 results and strategy update Ambition launch Investor roadshows with the leadership team post the ambition launch bp Annual Report and Form 20-F 2019 bp Sustainability Report 2019 Q2 First quarter 2020 results presentation Investor roadshows with executive management following first quarter 2020 results UKSA (retail shareholders’) meeting with the chairman Other institutional shareholder engagement with the chairman 2020 AGM bp Statistical Review of World Energy Q3 Second quarter 2020
results and strategy presentation Investor roadshows with executive management follow second quarter 2020 results and strategy Capital markets event – ‘bp week’ bp Energy Outlook presentation Investor roadshows with the bp leadership team – capital markets event Q4 Third quarter 2020 results presentation Investor roadshows with the bp leadership team following third quarter 2020 results
87 Corporate governance bp Annual Report and Form 20-F 2020 Workforce 2020 engagement We believe an engaged workforce is critical to us successfully delivering our strategy. When we talk about bp’s workforce, we include a wide
range of employees, contractors, agency and remote workers across all of our geographical locations. The board is responsible for overseeing and monitoring bp’s culture and its values. This extends to putting in place mechanisms allowing for workforce views to be reflected in board discussion and decision making, complementing existing mechanisms that are established by the leadership team. Such measures include employees being informed on matters of concern to them through bp’s intranet and local sites, social media channels, town halls, site visits and webinars including topics such as quarterly results, strategy, the low carbon transition and diversity. We also have a number of employee-led forums and business resource groups (BRGs) and aim to build constructive relationships with labour unions formally representing some employees. Employees are consulted on a regular basis through regular team and one-to-one meetings and
through our annual ‘Pulse’ survey. The board believes that the approaches and mechanisms described under Site visits, below, enabled effective engagement opportunities with the bp workforce. The board is satisfied that during 2020, these were effective alternatives to the proposed workforce engagement methods set out in Provision 5 of the UK Corporate Governance Code (the Code). Future of workforce engagement As part of its broader review of bp’s corporate governance framework, the board discussed whether its current approach to workforce engagement continues to be the most effective mechanism to inform its discussions and the decisions that it takes. Building on the experience that we have had, and the innovative approaches that were taken to workforce engagement through 2020, the board has sought to create a more rigorous framework so that there is clear channel through which the insights emerging from this engagement
process will be consolidated and considered in board discussions and decision making. The board also considered the significant changes to the workforce following reinvent bp and bp’s wide geographic spread and size. Taking all these factors into account, the board concluded that for 2021 workforce engagement is best overseen by the newly constituted people and governance committee. A regular programme of engagement has been developed. Some sessions have a specific engagement purpose while others will simply be an open opportunity to hear views, interests, ideas and concerns. It is intended that a number of these sessions will have no line managers to allow for an unconstrained exchange of views. Engagement locations will be varied across our global operations. Alongside this programme, the ‘Pulse’ surveys, bp ‘Keeping Connected’ sessions, site visits (even if virtual) and the chairman’s
programme of attendance at selected small team sessions will continue. The board believes the existing approaches and mechanisms described above enable comprehensive two-way engagement opportunities with bp’s workforce, and as such, is satisfied that these are effective alternatives to the proposed workforce engagement methods set out in Provision 5 of the Code. Looking beyond 2021 the board will continue to assess the effectiveness of its engagement with the workforce and how ultimately this informs the decisions that it takes, including the options provided for in the Code, for example appointing a director from the workforce. CEO ‘Keeping Connected’ webcasts During 2020 restrictions associated with COVID-19 disrupted planned opportunities for the board to engage with the bp workforce in person. As a result, most engagements were conducted virtually. Virtual engagements Our CEO Bernard Looney hosted a series of webcasts
featuring guests from across the organization to discuss a range of topics throughout the year, including bp’s new purpose, safety, mental health, and reinventing bp. Helge Lund, chairman of the board, joined the CEO as a speaker on two of these webcasts and non-executive directors were also invited to listen in. >12,500 average viewers per webcast Business resource groups and focus groups Non-executive directors engaged virtually with employees in BRGs and focus groups throughout the year, including virtual events organized by the Women in Wells, Future Talent and One Young World alumni forums. Through these engagements the directors heard directly from employees on a range of topics, including bp’s new purpose and strategy, employee sentiment – particularly during the reorganization of bp – the impact of COVID-19 on operations and wellbeing, diversity and career progression. Virtual site visits The
audit committee conducted a virtual visit and tour of bp’s trading floors in London and Houston and a majority of our non-executive directors attended a virtual visit of bpx energy’s Permian assets, led by the safety, environment and security assurance committee. During these visits, directors heard directly from the workforce regarding their perceptions of bp’s new strategy and how these businesses planned to implement it, as well as deepening their understanding of businesses and functions within bp.
88 bp Annual Report and Form 20-F 2020 Corporate governance continued We completely redesigned the bp corporate governance framework
in 2020, to more closely align with bp’s new purpose – reimagining energy for people and our planet – as well as our new strategy. The framework defines the board’s role, to promote the long-term sustainable success of the company, generating value for its shareholders while having regard to its other stakeholders, the impact of its operations on the communities within which it operates and the environment. The review had three main strands: 1. The role and purpose of the board The bp board believes that in order for governance to be effective it needs to have a regular review process across purpose, strategy, culture and values, while maintaining oversight of performance. Clearly defined terms of reference for the board were established together with a roadmap of activity that reflects those issues the board consider most important.
The board terms of reference identify certain matters that are considered to be of such materiality at a group level that they are reserved for approval by the whole board and cannot be delegated. The matters reserved include, among others, certain investments, entry into new countries, changes to the company’s capital structure, distributions and bp’s code of conduct. The full list is available on bp.com/governance. Governance framework governance and performance oversight Board Purpose Considers bp’s purpose, which underpins its decision making. Monitors whether bp’s strategy, values and culture remain in line with that purpose. Strategy Receives regular updates to test that the strategy and strategic direction established by the board continue to be the right approach for the long-term sustainable success of bp in line with its
purpose. Approves the annual plan and regularly monitors that it is aligned with the approved strategy, including reviewing business development, investment effectiveness and capita allocation. Conducts deep dives across each of the business groups and key strategic areas. Receives regular updates on progress towards the aims and objectives in the sustainability frame. Culture Reviews the ambition and aims of the people plan and in so doing assesses and monitors any impact on culture so as to satisfy itself that bp’s purpose, strategy and values continue to be aligned with its culture. Through the people and governance committee, reviews work on bp’s ways of working (including integration, agility, wellbeing, workplace, inclusion and digital). Values The board monitors bp’s values, ensuring that they are appropriate as the leadership team focuses on the execution of the new strategy.
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Corporate governance bp Annual Report and Form 20-F 2020 2. Committees A review of the board committees looking at their purpose, scope and authority with a focus on: Fit with the strategic direction of the bp board. Risk and allocation of the review of risk. Alignment with the new leadership structure to give clear oversight. The new committee structure under the board is depicted in the diagram (right) and described below. The nomination and governance committee was renamed the people and governance committee to reflect its wider remit in covering workforce engagement, wellbeing and talent management. The safety, environment and security assurance committee was renamed the safety and sustainability committee. Its remit has been widened to include monitoring the effectiveness of implementation of bp’s sustainability frame, see page 48. This is an important step in light of bp’s new purpose and ambition. The other permanent committees
– remuneration and audit – will remain. The results committee (comprising the chairman, CEO and chief financial officer (CFO)) also remains with delegated authority from the board to approve and authorize the release of the periodic financial statements and dividend announcements. The geopolitical committee has been replaced by a geopolitical advisory council rather than a board committee. It is attended by members of the board and the executive together with advisors who give a wider external view. The geopolitical highest priority risk is overseen at the board. Each of the four permanent committees has new terms of reference, adopted from 1 January 2021, to set out their role and responsibilities in a clear mandate, which can be found on bp.com/governance. The board will continue to review its framework annually to satisfy itself that it continues to be best aligned to bp’s purpose and strategy. 3. New ways of working
The board’s corporate governance review extended to documenting the responsibilities of the chairman, the CEO and the senior independent director so that their respective roles are clear both internally and to our external stakeholders. These are available on bp.com/governance. The board delegates day-to-day management of the business of the company to the CEO. This includes accountability to oversee the implementation of a comprehensive system of internal controls that are designed to, among other things, identify and manage the risks that are material to bp. The board continues to perform its oversight role and monitor bp’s performance. This responsibility extends to monitoring bp’s management and operations and obtaining assurance about the delivery of its strategy, and to oversee bp’s internal control and risk management
frameworks. The chairman holds meetings without executive directors present at the start or end of board meetings. The CEO is responsible for maintaining a dialogue with the chairman and the board on important and strategic issues facing bp. Strategic opportunities or issues which may arise, or which are on the CEO’s mind, are discussed at board meetings and the CEO welcomes constructive challenge from non-executive directors in light of their wider experience outside bp. The changes to bp’s purpose and strategy this year and bp’s journey towards becoming an Integrated Energy Company have given rise to the need for greater visibility on the decision- making criteria for capital expenditure and new business transactions. Accordingly, the board spends time examining and discussing the impact of portfolio changes such as strategic acquisitions and the allocation of capital, along with the annual plan, in order to gain a clear
understanding of the methodology of capital allocation. The board reviews capital investments that are more than $3 billion for resilient hydrocarbons, more than $1 billion for all transition or low carbon investments and, in addition, any significant inorganic acquisition that is exceptional or unique in nature. Clear information flows have been established between the board and the leadership team. This allows greater time at board meetings to focus on strategic and people topics, enabling a fuller understanding and quality discussion of the challenges to deliver our new strategy. Board and board committee structure Board People and governance committee Remuneration committee Audit committee Safety and sustainability committee
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bp Annual Report and Form 20-F 2020 The developmental needs of the board as a whole and for individual directors are regularly reviewed, so as to ensure that the board and individual effectiveness to board discussion and decision making are maximized. A formal and comprehensive induction is provided to all directors following their appointment. This includes meetings with management, technical briefings and site visits. Learning, development and induction Corporate governance continued Tushar Morzaria, appointed on 1 September 2020, undertook a tailored and robust induction against the challenging backdrop of COVID-19. The programme was adapted to accommodate the inability to participate in physical meetings and site visits. Digital solutions were therefore deployed to facilitate Tushar’s induction. Tushar looks forward to continuing his introduction to bp’s operations and learning more about the business and its people. The programme
included meetings with a wide range of senior management within bp, the external auditor and other key advisors. A selection of these and the areas of focus are outlined below. Board induction programme I am delighted to join the bp board and to contribute my expertise in support of bp’s new strategy. Tushar Morzaria Independent non-executive director Area Provided by Key topics covered Board and governance Helge Lund, chairman Ben Mathews, group company secretary Overview of board and committee matters. Priority areas for the board. Governance framework. Corporate structure. Audit committee Brendan Nelson, chair of the audit committee Jayne Hodgson, SVP, accounting, reporting, control David Jardine, SVP internal audit Doug King, Deloitte (external audit partner) Priority areas for the committee, including committee chair succession. bp’s financial position. Financial reporting framework and quarterly results close cycle. Internal
audit reports. External audit and quarterly review reports. Strategy and sustainability Giulia Chierchia, EVP strategy & sustainability bp’s new strategy and sustainability focus. Legal Eric Nitcher, EVP legal Overview of legal matters, including material litigation. Treasury Kate Thomson, SVP treasury Overview of treasury matters and liquidity risk management.
91 Corporate governance bp Annual Report and Form 20-F 2020 There is also a triennial requirement for this evaluation to be externally facilitated which will next fall due in 2021. The 2019 board evaluation highlighted three specific areas for action in 2020: Focus area Action taken Review
the skills, experience and diversity of the board, and the process for executive succession planning and talent management and development. The board skills matrix was used to focus NED recruitment and we have successfully recruited three NEDs with strong experience in areas which will complement and support bp’s new strategy and provide diversity of thought. The board, through the former nomination and governance committee, heard regular updates on the selection process and criteria for the bp leadership team and the next layer of leadership with a focus on building a future succession pipeline and the skills needed to drive the execution of bp’s new strategy. Satisfy itself that every member of the board has a deeper understanding of the board’s role in determining bp’s capital allocation process and in enabling more effective decision making. The board and leadership team have developed a process for greater
visibility of capital allocation at the board and evaluated the methodology of capital allocation. Capital allocation above agreed thresholds is now a matter reserved for the board. Redesign bp’s corporate governance framework, reinforcing the effectiveness of this control framework so that it is more closely aligned with bp’s new purpose and strategy. The board governance framework and ways of working were redesigned, details of which can be found on page 88. The 2020 board evaluation was an internal review. The chairman spoke with each director individually. The company secretary facilitated a theme-based review including, among other matters, portfolio management, the impact of the new board agenda, the evolution of bp’s purpose, strategy and values, stakeholder engagement and people matters. The review also looked at the composition
and diversity of the board and how effectively the directors work together. In early 2021, the board held a special meeting to discuss the feedback, focusing on strategic and operational oversight, board development and maintaining a dynamic and flexible approach to board and committee agendas. An action plan for areas of focus was agreed. Following this meeting, the senior independent director led a meeting with the non-executive directors without the chairman present to appraise his performance. The directors expressed their strong support for the continued leadership shown by the chairman. Board evaluation Each year bp completes a formal and rigorous annual evaluation of the performance of the board, its committees, the chairman and individual directors.
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bp Annual Report and Form 20-F 2020 Corporate governance continued People and governance committee The committee focused on identifying candidates who would enhance the strategic discussion in the boardroom and add to the diversity, skills and experience required as bp transitions to an IEC. Helge Lund Committee chair Chair’s introduction I am pleased to present my report as chair of the people and governance committee. During 2020, the committee reviewed the composition of the board and, with the new purpose and strategy in mind, focused on identifying candidates who would enhance the strategic discussion in the boardroom and add to the diversity, skills and experience required as bp transitions to an Integrated Energy Company. We discussed and guided the development of the new board governance framework to satisfy ourselves that bp continues to maintain the highest standards of governance and we reviewed bp’s workforce engagement mechanism
options in order to make a clear recommendation to the board. As part of the governance review, the committee was renamed as the people and governance committee with effect from 1 January 2021 to reflect its wider remit in covering workforce engagement, wellbeing and talent management. Looking to 2021, the committee agenda has been restructured to cover four matters: talent and capability, diversity and inclusion, engagement and culture and governance. Under that umbrella, we will oversee workforce engagement, engage an external provider for board effectiveness and continue to look at succession, leadership, talent, diversity and culture matters. Helge Lund Committee chair Committee overview Role of the committee The people and governance committee (previously called the nomination and governance committee, until 31 December 2020) seeks to ensure an orderly succession of candidates for directors, the
company secretary and senior executives and oversees corporate governance matters for the group. Key responsibilities Identify, evaluate and recommend candidates for appointment or reappointment as directors. Identify, evaluate and recommend candidates for appointment as company secretary. Review the mix of knowledge, skills, experience and diversity of the board for the orderly succession of directors. Review the outside directorships/commitments of the non-executive directors (NEDs). Review developments in law, regulation and best practice relating to corporate governance and make recommendations to the board on appropriate action, including on environmental, social and governance matters. Meetings and attendance The committee met seven times in 2020. All members attended each meeting with the exception of Brendan Nelson who missed one meeting owing to a prior commitment. Membership Helge Lund Member since July 2018 and chair since September 2018
Sir Ian Davis Member (resigned December 2020) Nils Andersen Member (resigned March 2020) Brendan Nelson Member Paula Reynolds Member Sir John Sawers Member
93 Corporate governance bp Annual Report and Form 20-F 2020 Activities during the year Reflecting its role in respect of board succession planning, early in 2020, the committee’s priority was to identify new non-executive directors to succeed two of the longer-serving members of the board – Sir Ian Davis and Brendan Nelson. Candidates were sought with the technical and professional skills to take on certain committee responsibilities, including in particular the chairmanship of the audit committee, plus
also candidates who would be able to support the chair of the board as the senior independent director. These characteristics were broadened so as to identify candidates who would also enhance the strategic discussion in the boardroom. External headhunters were engaged to support the process and identify candidates. These headhunters had no other connection to the company or its directors during the year. The search process led to the appointment of Tushar Morzaria in September 2020 and, from among the existing board members, Paula Reynolds as the senior independent director. Each of these appointments was considered to fulfil the search criteria, including the succession of the audit committee chairmanship. The committee also agreed new search categories for other NED candidates, broadly covering the areas of digital/technology and energy, reflecting the strategic
shift of bp to become an Integrated Energy Company and the dependency on digital as an enabler to transform companies. Karen Richardson and Johannes Teyssen together bring extensive financial, technological, transformation and energy industry experience to the board. Planning for new board members to help ensure a strong focus on strategic execution, safety and sustainability and connectivity to bp’s core businesses and markets continues. Committee meetings in 2020 included updates and discussions on the redesign of bp’s corporate governance framework, more details of which are set out on page 88. The committee received regular updates and challenged management on the reinvent bp proposals including the scale of the redundancies, the methodology associated with the selection process and details of the process controls and management of change to satisfy itself that safety would be maintained and a respectful process completed.
The committee heard detailed considerations on the workforce engagement mechanism options and discussed the benefits and issues of each option presented in order to make a recommendation to the board for 2021. Skills matrix Background and experience Energy markets Operational excellence and risk management Global business leadership and governance People leadership and organizational transformation Technology, digital and innovation Society, politics and geopolitcs Finance, risk, trading Non-executive directors Pamela Daley Ann Dowling Helge Lund Melody Meyer Tushar Morzaria Brendan Nelson Paula Reynolds Karen Richardson Sir John Sawers Johannes Teyssen
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bp Annual Report and Form 20-F 2020 Corporate governance continued Audit committee The committee was particularly focused on the impacts of bp’s reorganization and the COVID-19 pandemic on financial performance, the financial control environment and resilience. Brendan Nelson Committee chair Committee overview Role of the committee The committee monitors the effectiveness of the group’s financial reporting (including reporting on the financial aspects of climate matters), systems of internal control and risk management and the integrity of the group’s external and internal audit processes. Key responsibilities during 2020 Monitoring and obtaining assurance that the process to identify, manage and mitigate principal and emerging financial risks are appropriately addressed by the CEO and that the system of internal control is designed and implemented effectively in support of the limits imposed by the board (‘executive
limitations’). Overseeing the appointment, remuneration, independence and performance of the external auditor and the integrity of the audit process as a whole, including the engagement of the external auditor to supply non-audit services to bp. Reviewing the effectiveness of the internal audit function, bp’s internal financial controls and systems of internal control and risk management. Reviewing financial statements and other financial disclosures and monitoring compliance with relevant legal and listing requirements. Reviewing the systems in place to enable those who work for bp to raise concerns about possible improprieties in financial reporting or other issues and for those matters to be investigated. Meetings and attendance There were 10 committee meetings in 2020. All members attended each meeting with the exception of Pamela Daley who was absent from the March meeting owing to prior commitments. Regular attendees at the
meetings include the chief financial officer, SVP accounting reporting control, SVP internal audit, EVP legal and external auditor. Membership Brendan Nelson Member since November 2010 and chair since April 2011 Dame Alison Carnwath Member (resigned from the board in January 2021) Pamela Daley Member Paula Reynolds Member Tushar Morzaria Member since September 2020 (chair-designate) Brendan Nelson is chair of the audit committee. See page 76 for his biography. The board is satisfied that he is the audit committee member with recent and relevant financial experience as outlined in the UK Corporate Governance Code and competence in accounting and auditing as required by the FCA’s Corporate Governance Rules in DTR7. It considers that the committee as a whole has an appropriate and experienced blend of commercial, financial and audit expertise to assess the issues it is required to address, as well as competence in the oil and gas sector. The
board also determined that the audit committee meets the independence criteria provisions of Rule 10A-3 of the US Securities Exchange Act of 1934 and that Brendan may be regarded as an audit committee financial expert as defined in Item 16A of Form 20-F.
95 Corporate governance bp Annual Report and Form 20-F 2020 Chair’s introduction I am pleased to introduce the report on the audit committee’s activities during the year. During the year, the committee has continued to assist the board in fulfilling its oversight responsibilities, by monitoring the integrity of the group’s financial reporting and risk management systems, and also
by challenging management and external auditors across a number of key areas of focus, including key accounting judgements and control issues. In addition to the routine committee agenda for the year, the committee was particularly focused on the impacts of bp’s reorganization and the COVID-19 pandemic on financial performance, the financial control environment and resilience. I welcome the addition of Tushar Morzaria to the committee from September 2020. His broad financial experience is immensely beneficial to the committee and bp. Following year end, Dame Alison Carnwath stepped down from the committee and the board. I would like to thank her for her diligent contribution to the committee over the years. This is my last report as chair of the audit committee. I would like to thank my board and committee colleagues, as well as management, for the open, challenging and constructive nature of discussions we have conducted during my tenure.
As I hand over the committee chair to Tushar in May 2021, I remain confident that bp is well-positioned for continued resilience and success. Brendan Nelson Committee chair Activities during the year How the committee reviewed financial disclosure The committee reviewed the quarterly, half-year and annual financial statements with management, focusing on the: Integrity of the group’s financial reporting process. Clarity of disclosure. Compliance with relevant legal and financial reporting standards. Application of accounting policies and judgements. As part of its review, the committee received regular updates from management and the external auditor in relation to accounting judgements and estimates, including those relating to recoverability of asset carrying values. The committee keeps under review the frequency of results reporting during the year. In considering the bp Annual Report and Form 20-F, the committee assessed whether
the report was fair, balanced and understandable and also whether it provided the information necessary for shareholders to assess the group’s position and performance, business model and strategy. In making this assessment, the committee examined disclosures during the year, discussed the requirement with senior management, confirmed that representations to the external auditors had been evidenced and reviewed reports relating to internal control over financial reporting. The committee made a recommendation to the board, who in turn reviewed the report as a whole, confirmed the assessment and approved the report’s publication. How accounting judgements and estimates were considered and addressed The committee was briefed on a quarterly basis in 2020 on the group’s key accounting judgements and estimates. The primary areas of judgement and estimation which were considered by the committee are set out below. These areas
were discussed with management and the external auditor throughout the year and during the preparation of these financial statements. The committee is satisfied that the financial statements appropriately address the key accounting judgements and estimates both in respect of the amounts reported and disclosures made. During the year, the committee also considered and approved a change to bp’s accounting policy relating to physically settled commodity contracts, with effect from 1 January 2021. The committee’s process for considering key accounting judgements and estimates included an assessment of matters at various stages during the year. This primarily included the key accounting judgements and estimates set out on pages 98 and 99. The committee also considered and addressed key accounting estimates and judgements relating to provisions,
pensions and other post-retirement benefits, and supplier financing arrangements via briefings and review of the group’s assumptions. See Notes 23, 24 and 29 respectively for further information.
96 bp Annual Report and Form 20-F 2020 Corporate governance continued How risks were reviewed The principal risks allocated to the audit committee for monitoring in 2020 included those associated with: Trading activities: including risks arising from shortcomings or failures in systems, risk management methodology, internal control processes or employees. In reviewing this risk, the committee focused on external market developments and how bp’s
trading function had responded to a rapidly changing environment, including enhancing its control environment policies to strengthen its compliance and control culture. The committee further considered updates in the trading and shipping function’s risk management programme, including compliance with regulatory developments, activities in response to cyber threats, and efficiencies derived from more collaborative ways of working across group functions and businesses and the use of digital technologies. The committee also considered the impact of COVID-19 on operations and the control environment associated with trading activities, with particular reference to operational considerations associated with increased remote working. Compliance with business and regulations: including ethical misconduct or breaches of applicable laws or regulations that could damage bp’s reputation, adversely affect operational results and/or shareholder
value and potentially affect bp’s licence to operate. The committee reviewed the group’s programme on controls and contingencies for managing this risk, including enhanced approaches to monitor the risk in light of business evolution (such as an increase in venturing), as well as other internal and external trends. Cyber security risk: including inappropriate access to or misuse of information and systems and disruption of business activity. The committee reviewed ongoing developments in the cyber security landscape, including events in the oil and gas industry and within bp itself. The review focused on a strengthened approach in order to manage the ever-increasing threat of cyber risk and maintain cyber security, as the focus on a digital transformation across bp continues. Financial liquidity: including the risk associated with external market conditions, supply and demand and prices achieved for bp’s products which
could impact financial performance. The committee reviewed the key assumptions and underlying judgements used to manage the group’s liquidity and capital investments (including appraisal, effectiveness and efficiency). How other reviews were undertaken Other reviews undertaken in 2020 by the committee included the following, and in each case where the committee received segment and function reviews, each reported on strategy, performance, capability and risk management as well as on their first, second and third lines of defence policies as appropriate: Information technology and services: including the functions performance, strategy and optimization of core services to enable the digitization and modernization of bp at pace. bp ventures and Launchpad: including the purpose, capabilities, operating model, governance and performance of these entities. Reinvent bp programme: including a review of programme milestones and risks, as well as
business continuity and management of change. Tax: including strategy, performance, key drivers of the group’s effective tax rate, the global indirect tax environment, the tax modernization programme and the evolving approach to management of key risks. The committee also reviewed bp’s tax transparency report. Internal audit functional review: including a five-year plan for the function in a reinvented bp. Trading and shipping: including strategy, performance, capability and risk management. Effectiveness of investment: annual review of performance of projects with sanctioned capital over a certain threshold. Internal controls: assessments of management’s plans to remediate the external auditor’s control findings. How internal control and risk management was assessed Internal audit The committee received quarterly reports on the findings of internal audit in 2020, including their assessment of issues raised
in previous years, especially those relating to IT access controls. The committee also received a report from internal audit on their annual review of the system of internal control and risk management. The committee met privately with the SVP, internal audit and key members of his leadership team. The committee continued to monitor and review the effectiveness and capabilities of internal audit during the year. During the year, the committee received a report on the findings of an assessment conducted by internal audit of its conformance with the Internal Audit Code of Practice which was published in January 2020. The committee noted that internal audit conforms with the vast majority of recommendations set out in the code. Actions to achieve full conformance with the code were also noted. Training and briefings The committee considered market updates and developments throughout the year. This included technical accounting updates from the SVP accounting
reporting control on developments in financial reporting and accounting policy, as well as on accounting and disclosure changes that would be introduced as a result of the reorganization of the group. The committee also received briefings on specific topics, including non-operated joint ventures, and data analytics used by the external auditor. Site visit during the year In October 2020, the committee conducted a virtual visit of the trading & shipping function, including virtual presentations from the trading floor, covering low carbon trading, global power and global crude. Key areas of discussion during this site visit included the impacts of oil price volatility, COVID-19 and the reinvent bp programme on the business and its operations during 2020.
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Corporate governance bp Annual Report and Form 20-F 2020 FRC thematic review The bp Annual Report and Form 20-F 2019 was included in the FRC’s sample for its limited scope thematic review on reporting on the impact of climate change. bp subsequently received a letter request for information from the FRC’s Corporate Reporting Review team. The audit committee considered the letter and bp’s detailed response thereto, which enabled the FRC to close its enquiries. The committee notes the further enhancements made to disclosures in relation to climate change and the energy transition in this annual report. An FRC review provides no assurance that bp’s Annual Report 2019 was correct in all material respects. The FRC’s role was not to verify the information provided but to consider compliance with reporting requirements. Its letters are written on the basis that the FRC (which includes the FRC’s officers,
employees and agents) accepts no liability for reliance on them by bp or any third party, including but not limited to investors and shareholders. External audit How the committee assessed audit risk The external auditor set out its audit plan for 2020, identifying significant audit risks to be addressed during the course of the audit. These included: Impairment of upstream oil and gas property, plant and equipment. Impairment of exploration and appraisal assets. Accounting for structured commodity transactions. Valuation of level 3 instruments in trading and shipping revenue recognition. Management override of controls. The committee received updates during the year on the audit process, including how the auditor had challenged the group’s assumptions on these issues. How the committee assessed audit fees The audit committee reviews the fee structure, resourcing and terms of engagement for the external auditor annually; in addition it
reviews the non-audit services that the auditor provides to the group on a quarterly basis. Fees paid to the external auditor for the year were $54 million (2019 $49 million), of which 1.9% was for non-audit and other assurance services (see Financial statements – Note 36). The audit committee is satisfied that this level of fee is appropriate in respect of the audit services provided and that an effective audit can be conducted for this fee. Non-audit or non-audit related assurance fees were $1 million (2019 $1 million). Non-audit or non-audit related services consisted of other assurance services. How the committee assessed audit effectiveness Management undertook a survey which comprised questions across the following: (i) The main criteria to measure the auditor’s performance were: – Robustness of the audit process – Independence and objectivity – Quality of delivery – Quality of people
and service (ii) bp’s commitment to the audit; and (iii) Aligned audit approach – which sought to measure progress against the commitments from the audit tender. Year on year, the overall score from the survey increased by +3%. Improvements were seen across audit effectiveness and service quality, including a number areas of focus that had been identified in the previous survey. The committee also held private meetings with the external auditor during the year and the committee chair met separately with the external auditor and group head of audit at least quarterly. The effectiveness of the external auditor is evaluated by the audit committee. The committee assessed the auditor’s approach to providing audit services. On the basis of such assessment, the committee concluded that the audit team was providing the required quality in relation to the provision of the services. The audit team had shown the necessary commitment
and ability to provide the services together with a demonstrable depth of knowledge, robustness, independence and objectivity as well as an appreciation of complex issues. The team had posed constructive challenge to management where appropriate. How the auditor reappointment and independence was assessed The committee considers the reappointment of the external auditor each year before making a recommendation to the board. The committee assesses the independence of the external auditor on an ongoing basis and the external auditor is required to rotate the lead audit partner every five years and other senior audit staff every five to seven years. No partners or senior staff associated with the bp audit may transfer to the group. How the committee had oversight of non-audit services The audit committee is responsible for bp’s policy on non-audit services and the approval of non-audit services. Audit objectivity and independence is safeguarded
through the prohibition of non-audit tax services and the limitation of audit-related work which falls within defined categories. bp’s policy on non-audit services states that the auditor may not perform non-audit services that are prohibited by the SEC, Public Company Accounting Oversight Board (PCAOB), International Auditing and Assurance Standards Board (IAASB) and the UK Financial Reporting Council (FRC). The audit committee approves the terms of all audit services as well as permitted audit-related and non-audit services in advance. The external auditor is considered for permitted non-audit services only when its expertise and experience of bp is important. Approvals for individual engagements of pre-approved permitted services below certain thresholds are delegated to the SVP accounting reporting control or the chief financial officer. Any proposed service not included in the permitted services categories must be approved in advance either
by the audit committee chair or the audit committee before engagement commences. The audit committee, chief financial officer and SVP accounting reporting control monitor overall compliance with bp’s policy on audit-related and non-audit services, including whether the necessary pre-approvals have been obtained. The categories of permitted and pre-approved services are outlined in principal accountant’s fees and services on page 327.
98 bp Annual Report and Form 20-F 2020 Corporate governance continued Examples of how accounting judgements and estimates were considered and addressed Key judgements and estimates in financial report Exploration
and appraisal intangible assets Recoverability of asset carrying values Impact of climate change and the energy transition Audit committee activity Conclusions/outcomes bp uses technical and commercial judgements when accounting for oil and gas exploration, appraisal and development expenditure. Judgement is required to determine whether it is appropriate to continue to carry intangible assets related to exploration costs on the balance sheet. Determination as to whether and how much an asset, cash generating unit (CGU) or group of CGUs containing goodwill is impaired involves management judgement and estimates on uncertain matters such as future commodity prices, discount rates, production profiles, reserves and the impact of inflation on operating expenses. Reserves estimates based on management’s assumptions for future commodity prices have a direct impact on the assessment of the recoverability of asset carrying values reported in the
financial statements. Climate change and the transition to a lower carbon economy may have significant impacts on the currently reported amounts of the group’s assets and liabilities and on similar assets and liabilities that may be recognized in the future. Judgemental aspects of oil and gas accounting are reviewed routinely in bp’s quarterly due diligence process. Received the output of management’s annual intangible asset certification process used to verify that accounting criteria to continue to carry the exploration intangible balance are met. Reviewed policy and guidelines for compliance with oil and gas reserves disclosure regulation, including the group’s reserves governance framework and controls. Reviewed the group’s oil and gas price assumptions. Reviewed the group’s discount rates for impairment testing purposes. Upstream impairment charges, reversals and ‘watch-list’
items were reviewed as part of the quarterly due diligence process. Reviewed management’s best estimate of oil and natural gas price assumptions for value-in-use impairment testing. Reviewed management’s assessment of recoverability of exploration intangibles. Received briefings on decommissioning provisions. Significant exploration write-offs were recognized during the year (as disclosed in Note 8). Exploration intangibles totalled $4.1 billion at 31 December 2020. The group’s price assumption for Brent« oil and for Henry Hub«gas were revised downward and the period covered extended to 2050 as set out on page 28 and Note 1. Sensitivity analyses estimating the effect of changes in revenue and discount rate assumptions have been disclosed in Note 1. Significant impairments were recorded in the year as a result of the lower price assumptions as disclosed in Note 4. Headroom on goodwill
balances was reduced (see Note 14 for further information). Management’s revised best estimate of oil and natural gas prices are broadly in line with a range of transition paths consistent with the goals of the Paris climate change agreement. Exploration write-offs were recognized as a result of revised expectations to extract value from certain exploration prospects (see Note 8 for further information). Reasonable changes in the expected timing of decommissioning do not have a significant impact on the associated provisions.
99 Corporate governance bp Annual Report and Form 20-F 2020 Key judgements and estimates in financial report Impact of COVID-19
Investment in Rosneft Derivatives Audit committee activity Conclusions/outcomes The following areas involving judgement and estimates were identified as most relevant with regard to the impact of the COVID-19 pandemic and current economic environment: going concern, discount rate assumptions, oil and natural gas price assumptions, pensions and other post retirement benefits, impairment of financial assets measured at amortized cost and income taxes. Judgement is required in assessing the level of control or influence over another entity in which the group holds an interest. bp uses the equity method of accounting for its investment in Rosneft and bp’s share of Rosneft’s oil and natural gas reserves is included in the group’s estimated net proved reserves of equity- accounted entities. The equity-accounting treatment of bp’s 19.75% interest in Rosneft continues to be dependent on the judgement that bp has significant
influence over Rosneft. For its level 3 derivative financial instruments, bp estimates their fair values using internal models due to the absence of quoted market pricing or other observable, market- corroborated data. Judgement may be required to determine whether contracts to buy or sell commodities meet the definition of a derivative, in particular LNG« contracts. Received briefings on COVID-19 impacts as part of the quarterly due diligence process. Reviewed liquidity forecast assessments. performed to support the going concern assertion. Reviewed discount rates used for impairment testing and provisions. Reviewed management’s best estimate of oil and natural gas price assumptions for value-in-use impairment testing. Reviewed the judgement on whether
the group continues to have significant influence over Rosneft. Considered IFRS guidance on evidence of participation in policy-making processes. Received reports from management which assessed the extent of significant influence, including bp’s participation in decision making. Received regular reports on derivative accounting judgements. Received a briefing on the group’s trading risks and reviewed the system of risk management and controls in place. Reviewed the control process and risks relating to the trading business. bp continues to be resilient despite current economic conditions. The committee is satisfied with management’s assessment that the group will continue to operate as a going concern for at least 12 months from the date of approval of the financial statements. Material impairment charges and exploration write-offs were recognized in the Upstream segment as a consequence of price assumption changes.
See Note 1 for further information. bp’s CEO, Bernard Looney, was appointed to the Rosneft board of directors in June 2020. bp has retained significant influence over Rosneft throughout 2020 as defined by IFRS. See Note 1 for further information. bp considers that contracts to buy or sell LNG do not meet the definition of a derivative under IFRS. bp has assets and liabilities of $6.4 and $5.3 billion respectively, recognized on the balance sheet for level 3 derivative financial instruments at 31 December 2020 mainly relating to the activities of the trading and shipping function. bp’s use of internal models to value certain of these contracts has been disclosed in Note 30.
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bp Annual Report and Form 20-F 2020 Safety and sustainability committee The committee continued to work with the bp leadership team to promote safe and reliable operations. Melody Meyer Committee chair Committee overview Role of the committee The role of the safety and sustainability committee (SASC) (previously called the safety, environment and security assurance committee, until 31 December 2020) is to look at the processes adopted by bp’s executive management to identify and mitigate significant non-financial risk. This includes monitoring the management of personal and process safety risk, security and environment risks and receiving assurance that processes to identify and mitigate such non-financial risks are appropriate in their design and effective in their implementation. Key responsibilities during 2020 The committee receives specific reports from the business segments and functions, which include, but are not limited to, the safety
and operational risk function, shipping, internal audit and group security. The SASC can access any other independent advice and counsel it requires on an unrestricted basis. The SASC and audit committee worked together, through their chairs and secretaries, to ensure that agendas did not overlap or omit coverage of any key risks during the year. Meetings and attendance There were six committee meetings in 2020. All directors attended every meeting for which they were eligible. In addition to the committee members, all SASC meetings were attended by the CEO, the SVP for safety and operational risk (S&OR) and the SVP internal audit and/or his delegate. The EVP legal also attended some of the meetings. At the conclusion of each meeting the committee scheduled private sessions for the committee members only, without the presence of executive management, to discuss any issues arising and the quality of the meeting. The CEO receives invitations to
join the private meetings on an ad hoc basis and at least once a year the SVP internal audit is invited to a private meeting with the committee. Membership Melody Meyer Member since May 2017 and chair since November 2019 Nils Andersen Member (resigned March 2020) Professor Dame Ann Dowling Member Sir John Sawers Member Chair’s introduction I am pleased to present my second report as chair of the SASC. During 2020, the committee continued to work with the bp leadership team to promote safe and reliable operations within the organization. Operational risk management remained a key area of focus during 2020, against the challenging backdrop of the COVID-19 pandemic with the result that bp maintained a good safety record during the year despite these challenges. The committee (together with other non-executive directors) conducted a virtual visit of bpx energy Permian assets in December 2020. We were very impressed with the safety culture and performance
demonstrated by the bpx energy colleagues with whom we interacted during this virtual visit, and we look forward to being able to conduct a physical visit in due course. As part of the review by the board of its governance framework, the committee was renamed as the safety and sustainability committee with effect from 1 January 2021. The committee’s remit has also been expanded to include monitoring the effectiveness of the implementation of bp’s sustainability frame. This is an important step in light of bp’s new purpose and ambition and I look forward to continuing to work with the bp leadership team in furtherance of the new purpose, underpinned by safety and sustainability. Nils Andersen stepped down from the committee and the board in March 2020. I would like to thank him for his valuable contribution and commitment to the committee and I welcome Johannes Teyssen as a new member of the committee from the beginning
of 2021. Melody Meyer Committee chair Corporate governance continued
101 Corporate governance bp Annual Report and Form 20-F 2020 Activities during the year System of internal control and risk management The review of operational risk and performance forms a large part of the committee’s agenda. Internal audit provided quarterly reports on its assurance work and its annual review of the system of internal control and risk management. The committee also received regular reports from the CEO and SVP S&OR on operational risk, including regular reports prepared on the group’s health, safety, security and environmental performance and
operational integrity. These included meeting-by-meeting measures of personal and process safety, environmental and regulatory compliance, security and cyber risk analysis, as well as quarterly reports from internal audit. In addition, the SVP, internal audit regularly met in private with the chair and other members of the committee over the course of the year. During the year the committee received separate reports on bp’s management of risks relating to: Marine Wells Pipelines Explosion or release at our facilities Major security incidents Cyber security (process control networks) The committee reviewed these risks and their management and mitigation in depth with relevant executive management. The committee reviewed the 2020 forward programme for the internal audit function. The committee supported the remuneration committee in relation to remuneration policy. Virtual site visit In December 2020 the members of the committee (together
with the non-executive directors of the board) made a virtual visit to the bpx energy Permian site. Discussions during this visit covered a broad range of bpx energy health, safety and environment matters and provided an opportunity for effective virtual engagement with bpx energy staff. Corporate reporting The committee oversaw the bp Sustainability Report 2019. The committee reviewed the content and worked with the external auditor with respect to its limited assurance of selected sustainability KPIs.
102 bp Annual Report and Form 20-F 2020 Geopolitical committee The committee’s agenda developed and evolved during the year, reflecting a year with
a significant number of geopolitical developments globally. Sir John Sawers Committee chair Chair’s introduction I am pleased to report on the work of the geopolitical committee in 2020. The committee’s agenda developed and evolved during the year, reflecting a year with a significant number of geopolitical developments globally. Following changes to the board governance framework that took effect on 1 January 2021, the committee was replaced by a geopolitical advisory council. Although the council is not a formal committee of the board, its membership includes other directors, certain members of the bp leadership team and three external advisors, with myself as chair. The geopolitical highest priority risk is now overseen by the board as a whole, informed by feedback from the council. Sir John Sawers Committee chair Activities during the year Early in the year, the committee considered the potential impact on bp of policies and plans
of the new EU Commission and new UK government elected in December 2019. Later in the year, the committee considered the geopolitics of the COVID-19 pandemic and its impact on businesses and policies. The impacts of different potential outcomes of the November US election were discussed by the committee at its meeting in September 2020. The committee also received periodic geopolitical updates on a number of territories in which bp has significant interests throughout the year. Committee overview Role of the committee The committee monitors the company’s identification and management of geopolitical risk. Key responsibilities Monitor the company’s identification and management of major and correlated geopolitical risk and consider reputational as well as financial consequences. Review
bp’s activities in the context of political and economic developments on a regional basis and advise the board on these elements in its consideration of bp’s strategy and the annual plan. Major geopolitical risks are those brought about by social, economic or political events that occur in countries where bp has material investments. Correlated geopolitical risks are those brought about by social, economic or political events that occur in countries where bp may or may not have a presence but that can lead to global political instability. Meetings and attendance The chairman and CEO regularly attend committee meetings. The chief executive of Alternative Energy and executive vice president, regions and the head of government and political affairs attend meetings as required. The committee met three times during the year. All directors attended each meeting that they were eligible to attend, with the exception of Sir Ian Davis who
missed one meeting due to a prior commitment. Membership Sir John Sawers Member since September 2015 and chair since April 2016 Nils Andersen Member (resigned March 2020) Sir Ian Davis Member (resigned December 2020) Melody Meyer Member Corporate governance continued
103 Corporate governance bp Annual Report and Form 20-F 2020 Directors’ remuneration report Chair’s letter The committee wishes to place on record our gratitude for all that bp’s people achieved last year, and our acknowledgment of the challenging environment they faced. We look forward to better days ahead. Paula Rosput Reynolds Committee chair Contents Alignment
with strategy 108 2020 performance and pay summary 110 2018-20 performance share plan outcome 111 Executive directors’ pay for 2020 113 Wider workforce in 2020 115 Stewardship and executive director interests 118 Non-executive director outcomes and interests 121 Other disclosures 123 Policy implementation for 2021 124 Dear shareholder, Last year was enormously challenging – for the world and for bp. Yet the bp team operated safely and reliably, ran the business as well as could possibly be expected, and launched a strategic transformation of the company. That bp achieved so much last year is a credit to everyone in the company – from the leadership to the front lines. Together, they delivered the energy the world needs, and positioned the company
for the future. Nevertheless, as COVID-19 took its toll around the globe, there were consequences for bp’s financial outcomes in 2020. The remuneration committee always seeks to align employee reward with shareholder experience. Thus, despite extraordinary efforts on the part of the organization, we decided that there should be no 2020 pay-out for all those who normally participate in our broadly-applicable annual bonus plan. We know that this decision was painful for bp’s people, many of whom count on earning a cash bonus as part of their personal and family financial planning. While words cannot substitute for remuneration not received, the committee wishes to place on record our gratitude for all that bp people achieved amidst the environment they faced. We look forward to better days ahead. Shareholder engagement Throughout this challenging period when we had many decisions to make regarding metrics and reward, the committee
has benefited from engagement with our shareholders. The remuneration policy under which we now operate was directly shaped by a meeting we held with bp’s top 25 shareholders and other proxy representatives in 2019. We appreciated shareholders’ overwhelming support (96.58% approval) of the new policy at our AGM last May. Throughout 2020, we have continued to meet (virtually) with our largest shareholders to discuss a range of performance and incentive topics in detail. We are grateful for your counsel and hope you will see your advice reflected in the decisions which we have reached. We ask for your support of this directors’ remuneration report, and the decisions described herein, at the forthcoming annual general meeting.
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bp Annual Report and Form 20-F 2020 Directors’ remuneration report continued In this report, the committee continues its practice of scrutinizing both one- and three-year performance. Even in the absence of paying annual bonuses for 2020, we have included some discussion on results to give a balanced view of what worked well and what disappointed. This report covers our decisions for 2020 and the details regarding our implementation of the 2020 remuneration policy for 2021 and beyond. The highlights are provided immediately below. Key remuneration outcomes for 2020 No pay-out under our 2020 annual bonus plan. There was no pay-out under the annual bonus plan for any of the participating employees Lower vesting for the 2018-2020 equity plan. The vesting outcome for our 2018-20 performance shares cycle is 32.5% of maximum, down from 71.2% in the previous cycle, and from an average of over 66% over the last six cycles. It is worth noting that the committee
made no alterations to the performance measures or targets on which these awards were based, nor any discretionary adjustment to the vesting outcome. This vesting outcome applies equally to our former executive directors, and to our new CEO and CFO in respect to their pre- appointment performance share awards. Key remuneration decisions for 2021 and beyond To recognize the efforts of the wider workforce, virtually all employees will receive an above-market pay increase in 2021. Large numbers of our employees received no pay adjustment in 2020 or had their increase deferred for six months. Given the large reduction in headcount and all the responsibility this action places on those who remain, we agreed with management’s plan to increase salaries across-the-board, and ahead of market. Any time salaries rise, the cost of other remuneration that hinges off salary rises as well. At the same time, we are obligated to monitor disparate impacts
and overall welfare of the workforce. We will, therefore, continue to monitor and balance the costs of the programme with wider workforce pay issues. We considered the approach to salary for our executive directors apart from the wider workforce. We embrace restraint as a guiding principle, but restraint must be balanced with fair reward for contribution. The board has been gratified by the immediacy of Bernard Looney’s impact in leading the organisation, and in refreshing bp’s purpose, strategy and organisation. We propose to recognize his efforts with an increase of 2.75% salary with effect from the annual general meeting. This increase is significantly lower than the increase that our UK professional workforce will receive on their pay review date in 2021. Murray Auchincloss has likewise made an immediate impact since his appointment. He fully assumed the challenges of the CFO role and has forged a strong partnership alongside Bernard.
We set his initial salary in 2020 at a level below comparable rates for finance directors in the FTSE 30, until we could be certain of the contribution he would bring to the role. Shareholders will recall our policy is to keep executive increases within the boundary of wider workforce increases, except in specific circumstances. We find that Murray is already contributing beyond our expectations of even a seasoned CFO. Given his criticality to the execution of our strategy, we conclude that adjusting his below-market salary is such a specific circumstance. We therefore intend to increase his salary by 8% to £750,500, following the annual general meeting, placing him in line with the median rate for FTSE 30 CFOs. It is our intention, subject to the committee’s view of Murray’s continued development and success in role, to bring his salary in line with that of his predecessor and other CFOs in similarly challenging roles.
We anticipate that this may require increases somewhat above the wider workforce average in the future. In 2021 we have made an all-employee share award to allow employees to participate in the success that a reinvented bp can deliver. The majority of employees will receive restricted shares vesting in 2025, while more senior employees will receive share options to be exercised from 2025 onward and with a ten-year term. We are bringing our metrics and targets for both the 2021 annual bonus and the 2021-23 performance share into line with bp’s new strategy and the refreshed commitments to financial performance. The changes are described in detail in this report and we hope you will see how closely we have sought to align these targets to the commitments that management have articulated to investors. The 2021-23 awards will be in line with approved policy and the grant size is unchanged from prior years. All share awards will be granted
after the annual meeting and pricing will be based on the preceding 90 days. Overview of financial performance, operating achievements, and strategic progress Our 2020 annual bonus plan consisted of measures associated with financial performance and operations. Our long-term share plan consisted of financial measures and strategic progress. Each area of performance is summarized below to provide a sense of how we evaluated overall performance. Financial performance for bonus purposes was measured in terms of underlying replacement cost profit and free cash flow. For performance shares, we measured return on average capital employed (ROACE) and relative total shareholder return (rTSR). In neither the short nor the long-term plan did actual financial performance meet targets. Over the three-year performance period, however, bp ranked third out of the five super- majors for rTSR purposes which accounted for a modest 12.5% vesting of the 2018-20 performance
share grant. To offer some perspective, we note that during 2020 the company reduced net debt by $6.5 billion to $39 billion. In announcing the sale of a share of bp’s interest in Oman’s Block 61, we continue making good progress towards the 2025 target of $25 billion of proceeds from divestments. Importantly, too, management initiated the review of bp’s portfolio of assets in 2020 and recommended significant impairments and exploration write- offs. Thus, management took the necessary steps to address the value of our assets given the energy transition, in full knowledge that they would forego near-term benefit because of these actions. We think this reflects well on the system of reward – not paying when performance is below expectations – but also on the integrity of the leadership which is nonetheless doing the right
thing to create a sustainable future.
105 Corporate governance bp Annual Report and Form 20-F 2020 Despite the challenges of the pandemic, operations were strong in 2020, with refining availability of 96%, upstream plant reliability of 94%, and delivery of four new major projects. Safety trends were also positive, with process safety events, recordable injury frequency, and other key safety and environmental metrics significantly lower than in 2019. While workforce hours were down, bp people safely managed increased COVID-19-related risks and travel restrictions, and increased quarantine periods associated with cross-border crew rotations, while ensuring safety
critical staffing and emergency response preparedness. bp teams also delivered above-target sustainable emissions reductions in 2020. Strategic progress is the other area we assessed; in the 2018-20 performance share plan it carried a 20% weight. As we consulted with shareholders, we can appreciate that the inclusion of ‘strategic progress’ in a scorecard can be a double-edged sword. On the one side, measuring strategic progress more specifically aligns our strategy and the reward we will confer. On the other side, strategic progress does not always carry with it straightforward metrics that are more typically used in remuneration designs. Thus the committee must use its judgement and explain its rationale. We do so here on page 111. We hope you will agree that we’ve been thoughtful in evaluating the organization’s strategic performance over the 2018-20 period. Other decisions and forward-looking activity In
our approved 2020 remuneration policy, we retained flexibility to adjust performance measures and weightings in both our annual bonus and performance share plans. Given the shift in the business mix and the exigencies of our financial frame, for the 2021 annual bonus, we are introducing two new financial measures: cumulative cash cost reductions (weighted at 25%); and an operational measure to reflect margin share from convenience retail and electrification (weighted at 10%). These changes Remuneration committee Role of the committee The role of the committee is to determine and recommend to the board the remuneration policy and to set chair, executive director and leadership team remuneration. It reviews workforce remuneration and monitors related policies, satisfying itself that incentives and rewards are aligned with bp’s culture. In determining the policy, the committee takes into account various factors, including workforce remuneration,
and structures the policy to promote the long-term success of the company and linking reward to performance. Key responsibilities Recommend to the board the remuneration principles and policies for the executive directors while considering remuneration and related policies for employees below the board and the executive team. Set and approve the terms of engagement, remuneration, benefits and termination of employment for the executive directors, leadership team and the company secretary in accordance with the policy. Prepare the annual remuneration report to shareholders to show how the policy has been implemented. Approve the principles of any equity plan that requires shareholder approval. Ensure termination terms and payments to executive directors and leadership team are fair. Receive
and consider regular updates on workforce views and engagement initiatives related to remuneration, insight from data sources on pay ratio, gender pay gap and other workforce remuneration outcomes as appropriate. Maintain appropriate dialogue with shareholders on remuneration matters. Membership Paula Rosput Reynolds Member since September 2017 and chair since May 2018 Nils Andersen Member (resigned March 2020) Pamela Daley Member Sir Ian Davis Member (resigned 30 December 2020) Melody Meyer Member since March 2020 Brendan Nelson Member Meetings and attendance The chairman and the CEO attend meetings of the committee except for matters relating to their own remuneration. The CEO is consulted on the remuneration of the CFO, the leadership team and more broadly on remuneration across the wider employee population. Both the CEO and CFO are consulted on matters relating to the group’s performance. bp’s EVP people and culture, SVP
reward and wellbeing and advisors attend meetings and other executives may attend where necessary. The committee consults other board committees on the group’s performance and on issues relating to the exercise of judgement or discretion as necessary. The committee met nine times during the year. All directors attended each meeting that they were eligible to attend, except Sir Ian Davis who was not able to attend two meetings, and Pamela Daley and Brendan Nelson who each missed one committee meeting. represent the committee’s best judgment for fine-tuning measures to the new strategy. While we are adding two new measures, we will continue to measure annual performance of our operations, of cash generation, of sustainable emissions reductions and of safety. For the 2021-23 performance share awards, we will introduce an earnings per share growth (EBIDA CAGR) measure alongside the existing ROACE measure (each weighted at 20%), and will
reduce the weighting on rTSR (from 40% to 20%). Many of you will recall that the relevance of rTSR and the selection of an appropriate peer group were widely, but inconclusively discussed, during our September 2019 stakeholder engagement session. Against that backdrop, our judgment is that if the bp team can achieve the multi-year financial results to which it committed in July 2020, then the team should be rewarded, with only a modest calibration to what other energy companies accomplish over these three years.
106 bp Annual Report and Form 20-F 2020 Directors’ remuneration report continued In this directors’ remuneration report RC profit (loss),
underlying RC profit, return on average capital employed, operating cash flow excluding Gulf of Mexico oil spill payments, margin share for convenience and electrification, net debt and cumulative cash cost reductions are non-GAAP measures. These measures, together with upstream plant reliability and refining availability, are defined in the Glossary on page 341. Also noteworthy for the 2021-23 performance share awards, we are recasting the strategic progress measures to three well-defined areas: (1) delivering value through a resilient and focused hydrocarbon business; (2) building scale and value through investments in lower carbon electricity and energy sources; and (3) accelerating growth in convenience and mobility. Strategic progress metrics will be weighted at 40%. Several shareholders have asked us to be more specific about which measures from the September 2020 presentations we intend to use in evaluating strategic progress, and I say more
on this at page 109 in the alignment to strategy section. The leadership team has been bold in seeking to transform bp and has shown exemplary cooperation in developing these challenging performance measures. Wider workforce and activities through the pandemic Much of the committee’s time this year was dominated by the pandemic, which had a serious impact on workforce and remuneration matters. With our plans to reinvent bp already proceeding when the pandemic hit, bp’s leadership committed that no redundancies would take place for a minimum of three months to allay immediate concerns about job security. Also, bp sought no pandemic relief in the form of grants or furlough funding from any governments anywhere in the world. Despite the limited ability to meet in person, the committee and the board engaged with employees virtually throughout the year. Despite the fact that 2020 was a year with many discouraging moments, we find that
the employees are highly engaged – and willing to speak their minds – which bodes well for the future. From the outset of the pandemic’s impact, mental health as well as physical well-being were of concern. Both Bernard and our chair Helge Lund donated 20% of their salaries to charities dealing with mental health issues from April 2020. In addition, Bernard directed the company to make a substantial donation to the UK mental health charity, Mind. This generosity is consistent with the leadership’s support for mental health within the company, and given the duration and far-reaching effects of the pandemic, was exceptionally far-sighted. Closing thanks Following their retirement from the board, I thank Nils Andersen and Sir Ian Davis for their many
contributions to this committee, while welcoming Melody Meyer and, most recently, Tushar Morzaria. At the annual general meeting, Brendan Nelson plans to stand down and his particular brand of sober judgement will be greatly missed by the committee. The technology we have all deployed in the last year has only served to enhance our consultation with shareholders and their advisors. These virtual face-to-face contacts from our respective homes have allowed for frequent conversations. We thank you for fitting us into your long days, and as you review the details provided in this report, we welcome your comments. Paula Rosput Reynolds Chair of the remuneration committee 22 March 2021
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Corporate governance bp Annual Report and Form 20-F 2020 Remuneration at a glance Purpose and key features Outcomes for 2020 Implementation in 2021 Salary and benefits Fixed remuneration reflecting the scale and complexity of our business, enabling us to attract and keep the highest calibre global talent. Reviewed annually and, if appropriate, increased following the AGM. Benchmarked to market at inception with increases limited to those of our wider workforce, except in specific circumstances. Bernard Looney’s salary set at £1,300,000 on appointment. Murray Auchincloss’s salary set at £695,000 on appointment. Bob Dudley’s salary unchanged at $1,854,000 until cessation. Brian Gilvary’s salary unchanged at £790,500 until cessation. Benefits were unchanged. Bernard’s salary to increase by 2.75% to £1,335,750 from the AGM. Murray’s salary to increase
by 8% to £750,500 from the AGM. Benefits to remain unchanged. Retirement benefits To recognize competitive practice in home country. Bernard is a deferred member of a UK final salary pension plan, but now receives a cash allowance in lieu of retirement benefits. Murray is a deferred member of a US final salary pension plan, but now receives a cash allowance in lieu of retirement benefits. Bob was a member of both a US final salary pension plan and a US retirement savings plan. Brian was a member of a UK final salary pension plan and received a cash allowance in lieu of further service accrual. Bernard has no further service accrual for his deferred pension, and the pension calculation will be based on his pre-appointment salary. His cash allowance is fixed at 15% of salary. Murray has no further service accrual for his deferred pension arrangement, and the pension calculation will be based on his pre-appointment salary. His cash allowance
is fixed at 15% of salary. Bob’s defined benefit pension did not increase in 2020. bp actual and notional retirement savings plan contributions of $32,445 were more than offset by investment losses within his plans, hence he received no net benefit in 2020. Brian’s defined benefit pension increase was below inflation. His cash allowance was 30% of salary to 30 May, and 25% of salary from 1 June 2020. Bernard’s cash allowance will be unchanged at 15% of salary, and he accrues no further value under his deferred pension. Murray’s cash allowance will be unchanged at 15% of salary, and he accrues no further value under his US deferred pension. Annual bonus To incentivize delivery of our annual and strategic goals. 112.5% of salary at target, and 225% at maximum. To reinforce the long-term nature of our business and the importance of sustainability, 50% of the bonus is paid in cash and 50% is mandatorily deferred
and held in bp shares for three years. No bonus for 2020. For our 2021 bonus, our scorecard will be reweighted to safety (15%), environment (15%), operational (20%) and financial (50%), as described on page 125. Performance shares To align reward to our strategy and long-term performance. Vesting outcomes vary relative to our financial returns and strategic priorities. Annual grant of performance shares, representing the maximum outcome. 500% of salary for the chief executive officer and 450% of salary for chief financial officer. Awards granted in 2018 (under our 2017 policy) were assessed against our balanced scorecard of financial (80%) and strategic progress (20%) measures. Our 2018-20 performance share outcome is 32.5% of maximum vesting. Awards granted in 2019 (under our 2017 policy) will vest in proportion to success against the measures of our 2019-21 scorecard. For the 2021-23 cycle (under our 2020 policy), grant levels will remain
unchanged at 500% for Bernard and 450% for Murray, with weightings of 20% each for rTSR, ROACE and EBIDA CAGR, and 40% for strategic measures, as shown on page 125. Shareholding requirement To ensure sustained alignment between shareholder and executive director interests. The chief executive officer and other executive directors are required to maintain shareholdings equivalent to 500% and 450% of salary respectively, including for two years post employment (2020 policy). Both former executive directors materially exceed their post- employment share ownership requirements of two and a half times salary (pre-dating the 2020 policy). Bernard and Murray have not yet achieved their minimum shareholding requirement (they must do so within five years of appointment). The minimum shareholding requirements remain unchanged.
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A sustainability frame linking our purpose and Integrating energy systems Partnering with countries, cities and industries Driving digital and innovation Low carbon electricity and energy Convenience and mobility Resilient and focused hydrocarbons bp Annual Report and Form 20-F 2020 Directors’ remuneration report continued Alignment with strategy The frame for our remuneration policy and practice Last year we refreshed our remuneration policy following wide consultation, individually and collectively, with shareholders. Through that consultation we decided to retain the strongly performance-oriented reward model that served us well in the previous decade. Thus, we retained and built upon the established policy structure, with the advantage this brings of being well- understood and accepted by our executives and wider workforce alike. By design, this refreshed policy allows for ongoing alignment to the nearer-term needs of our strategy, with measures
intended to evolve in line with the pace and form of the energy transition. This design reflected the four broad themes that emerged from our engagement with shareholders: A clear end-to-end alignment from strategy, through measurable performance indicators and reward outcomes, to shareholder experience. To balance our contribution to the energy transition with delivering shareholder returns, with encouragement to use appropriate discretion given the complexity of the environment in the energy transition. To ensure strategic measures align to long-term sustainability, relative to a wide peer group. To use meaningful and transparent performance indicators reflecting our progress in the energy transition and reductions to our carbon impact. bp’s purpose, ambition and strategy bp’s purpose, to reimagine energy for people and our planet, is complemented with a clear and unambiguous ambition – to be a net zero company
by 2050 or sooner and to help the world get to net zero. Our strategy is transformational, to pivot from International Oil Company to Integrated Energy Company, from a focus on developing resources, to a focus on delivering solutions for customers. As seen below, this strategy is grounded in three focus areas and three sources of differentiation, set within a sustainability frame linking our strategy to our purpose. Connecting remuneration to strategy Alignment with strategy is evident in: Clearly measurable safety, sustainability, strategic and financial measures for each cycle of annual bonus and/or performance shares. The judgements we make to assess qualitative progress against strategic objectives. Our ‘underpin’ assessment to take safety outcomes into account prior to determining the final performance shares vesting percentage. Our overarching discretionary decisions to ensure share plan outcomes reflect shareholder experience,
environmental, societal, and other inputs. Achieving balance between safety, sustainability, strategic and financial measures is an essential consideration for the committee in applying policy. Considering the three ‘focus areas’ of bp’s strategy, generating cash from our resilient and focused hydrocarbons business is the critical element to support bp’s transition into the two growth areas – low carbon electricity and energy, and convenience and mobility. We expect bp to be directing 40% or more of its investment into these areas by 2030, but that reallocation of spend will be a gradual and non-linear matter, requiring flexibility and judgement from leadership. Our commitment is to oversee this transition with care, applying remuneration policy to incentivize results in the most critical areas. In our most recent consideration we have therefore aligned the strategic performance measures of our 2021-23
performance share awards entirely to the three ‘focus areas’ of bp strategy: low carbon electricity and energy; convenience and mobility; and resilient and focused hydrocarbons. This means that, for now, we are consciously not introducing measures related to the three ‘sources of differentiation’, in the belief that we need to limit the total number of measures and highlight those which are the most pressing. This has also led us to review our decision- making from last September when we set strategic measures for the 2020-22 performance share awards. At that time, we had chosen four strategic elements – two of the focus areas, and two of the sources of differentiation. With the hindsight of our more recent discussions and a deeper understanding of how the strategy is likely to yield most value, we realise those earlier decisions were not the best. Therefore, we are taking the unusual step of amending
our 2020-22 strategic progress measures mid-cycle, to align them instead with the measures of our 2021-23 cycle. Thus we bring focus to the most critical areas, align the measures for the first two cycles of share award under our 2020 policy, and can develop a common set of performance metrics that will allow us to transparently report progress across all three cycles of award under the 2020 policy (ie. those starting in 2020, 2021 and 2022). The table on page 109 summarizes the alignment between performance measures and strategy, showing the weightings associated with each.
109 Corporate governance bp Annual Report and Form 20-F 2020 Aligning performance measures
and strategy 2020 annual bonus 2021 annual bonus 2020-22 performance shares 2021-23 performance shares Safety, our core value 20% 15% Underpin Underpin Low carbon – – Convenience and mobility – 10% Resilient hydrocarbons 10% 10% Integrating energy – – – – Partnering – – – – Digital – – – Sustainability 20% 15% – – Financial frame 25% cash flow 25% profit 25% cash flow 25% cumulative cash cost reduction 40% rTSR 30% ROACE 20% rTSR 20% ROACE 20% EBIDA CAGR Looking forward, strategic progress for the 2020-22 and 2021-23 performance shares will be a largely qualitative assessment by the committee, supported by key performance indicators that will enable us to add a quantitative overlay in our assessments and to allow reporting on progress through the concurrent cycles of each award. These indicators
are as follows: Resilient and focused hydrocarbons Production costs per barrel: track improvement in unit production cost per barrel to help deliver margin efficiency. Plant reliability: measure the reliability of upstream production assets as an indicator of operational efficiency. Refining availability: measure the availability of downstream refining assets, also as an indicator of operational efficiency. Demonstrate track record, scale and value in low carbon electricity and energy Gigawatts of developed renewables energy: confirm the growth and value added from new renewable energy projects. Clear decisions on other energy platforms: demonstrate strategic progress in the selection of energy platforms for future growth. Renewables pipeline: build a renewable pipeline in alignment with 2025 and 2030 goals while consistent with targeted returns. Accelerate growth in convenience and mobility Castrol performance: demonstrate growth momentum in Castrol. Strategic
convenience sites: confirm the number of strategic convenience sites. Margin share from convenience and electrification: demonstrate the capture of growth from the energy transition through the retail network via measuring the ratio of convenience and electrification gross margin to total consumer energy (retail fuels and electrification) and convenience gross margin. 30%{ 40%{
110 Bernard Looney CEO from 5 February 2020 Murray Auchincloss CFO from 1 July 2020 Bob Dudley CEO to 4 February 2020 Brian Gilvary CFO to 30 June 2020 1. Salary and benefits 2. Retirement benefits 3. Annual bonus 4. Performance shares 1. 2. 4. £1.74m 2019: n/a 1. 2. 4. £0.62m
2019: n/a 1. $0.19m 2019: $13.3m 1. 2. £0.55m 2019: £6.6m Bernard Looney, CEO Murray Auchincloss, CFO 1.24 times salary, 543,939 shares 0.60 times salary, 141,535 shares Policy requirements Actual bp Annual Report and Form 20-F 2020 2020 performance and pay outcomes Business performance Performance outcomes Total remuneration 2020 See page 113 for detail. Share ownership 3rd Among peers for total shareholder return 2018-20 $13.8bn Operating cash flow excluding Gulf of Mexico oil spill payments $6.4bn Total dividends paid to shareholders 32.5% Formulaic outcome (% of maximum) 0% Committee judgement, no adjustment 32.5% Final outcome (% of maximum) No bonus Formulaic outcome (% of maximum) n/a Committee judgement n/a Final outcome (% of maximum) Performance dimensions (% weighting) Annual bonus outcome (% of maximum) Bernard Looney Nil Murray Auchincloss Nil Bob Dudley Nil Brian Gilvary Nil Performance dimensions (% weighting)
Performance shares outcome (32.5% of maximum) Bernard Looney £0.35m Murray Auchincloss £0.22m Bob Dudley $1.57m Brian Gilvary £0.62m Key strategic highlights Completed the Southern Gas Corridor pipeline system, with the Trans Adriatic pipeline beginning gas deliveries. Agreed to sell our petrochemicals business to INEOS. Added ~300 strategic convenience sites across our retail network, bringing the total to 1,900. An exceptional year of challenge and internal reinvention Robust safety and operating outcomes, but plan unaffordable. Strong strategic progress, weak financials. Shareholding is a key means by which the interests of executive directors are aligned with those of shareholders. The CEO and CFO shareholdings are shown below, as at 2 March 2021. Both these new executive directors are building towards the policy requirement, which is mandatory within five years of appointment. 2018-20 performance shares No bonus for 2020 Safety
(20%) Environment (20%) Operational (10%) Financial (50%) Financial (80%) Strategic progress (20%) KPI KPI KPI This legend denotes remuneration measures that directly relate to bp’s key performance indicators. See page 39. 2020 annual bonus 20/20 12.5/80 Directors’ remuneration report continued
111 Corporate governance bp Annual Report and Form 20-F 2020 2018-20 performance share plan outcome Vesting under our performance share plans is assessed using the group performance scorecard shown on page 112, and subject to any discretionary adjustment by the committee. Bernard and Murray were granted 2018-20 performance share awards under the Group Share
Value Plan (GSVP) for bp group leaders, rather than under the Executive Director Incentive Plan (EDIP). The GSVP and EDIP both use the same scorecard, therefore the comments in this section apply equally to our former and new executive directors, as well as our group leaders, even though they relate to performance shares awarded under different plans. The financial outcomes for the three-year period were disappointing. Return on average capital employed averaged 2.6% over 2019 and 2020 (the ROACE measurement period for this cycle), below our threshold level for vesting on this measure. Total shareholder returns turned negative for bp, alongside all our constituent peer companies. bp placed third among our competitor group, however, which yielded formulaic vesting of 12.5% (of a potential 50%). To counter the impact of share price volatility in TSR measures, bp has continued its standard practice of averaging US market prices over the fourth quarter immediately
before, and at the end of, the three-year performance cycle. Peers in our competitor group may use different pricing methods, leading them to report different ranking outcomes from bp. As reported last year, we introduced four strategic progress measures in our 2017 policy, and this is now the second cycle for which we have made an assessment on strategic progress. These were the measures that then positioned bp for the future, and the committee found that in all four strategic areas the business has delivered fully against intended outcomes. Thus vesting on this element of the scorecard is determined to be 20%. The key factors that formed our scoring decision were: Growing gas and advantaged oil in the upstream. Gas production grew from 1.11mmboed in 2017 to 1.15mmboed by 2020, with eight major gas projects started up in the period. In the same period bp started up seven major oil projects and have a further eight major oil projects under construction.
We purchased BHP tight oil assets, accessing some of the best basins onshore in the US. Market-led growth in the downstream. We have continued strategic progress with our convenience partnership model now in around 1,900 sites across the network, with 800 opened since 2017. The growth has been driven by the roll-out of REWE to Go in Germany, our Thorntons business in North America, and new partnerships launched in South Africa, Australia, New Zealand and Portugal. Retail store gross margin has grown 6% per annum since 2017 to over $1bn and is showing resilience despite COVID-19. In growth markets, we doubled our retail sites to 2,700 in 2020, expanded our network to over 500 bp-branded retail sites« in Mexico, and opened over 1,400 sites in India with our Reliance joint venture. In our sustainable aviation fuel business, we added 13 new locations to Air bp’s supply network and have struck an innovative collaboration with Neste for supply of
sustainable aviation fuel. We have made a further $40 million investment in Fulcrum since 2017. Venturing and low carbon across multiple fronts. Lightsource bp now has a presence in 14 countries, up from five in 2018. We have created a differentiated strategy in electric vehicle charging through bp pulse and Storedot, which has demonstrated five-minute charging capability. Our focus on reducing emissions has progressed well, with a reduction from 48.8Mte in 2018 to 41.7Mte in 2020, aligning with our net zero ambition. Our 2020 methane intensity is estimated at 0.12%, well below our target of 0.2% Gas power and renewables trading and marketing growth. We remain the largest US gas and power marketing company. In 2018 and 2019 we added six advanced liquified natural gas (LNG) tankers to the bp-operated fleet; our Tangguh LNG expansion started drilling in 2019; and Train 2 of our Freeport LNG began commercial operations in 2020, with first gas deliveries from
bp under our 20-year tolling agreement. Along with the combination of financial and strategic measures, the committee considers an ‘underpin’ decision before deciding on the final result, taking a broader view to ensure that the reward outcome aligns with absolute shareholder returns, safety and environmental factors, and low carbon and climate change considerations. The committee has been mindful of the need to take an even broader perspective, and thus consider executive outcomes in relation to societal matters in general and our wider workforce in particular. While absolute returns disappoint, we find that all aspects of the underpin support at least 32.5% vesting, which from a participant’s perspective reflects a poor return for the efforts expended. Therefore, our overall judgement is to leave the vesting outcome unadjusted. As mentioned above, this scorecard outcome applies to all participants in both the EDIP (for executive
directors) and the GSVP (for group leaders). With time pro-ration for Bob and Brian to reflect their periods of service during the three-year performance period, this vesting delivers the outcomes detailed below. For Bernard and Murray these values are included in the single figure table on page 113, whereas for Bob and Brian they are reported in the payments for past directors section at page 122. 2018-20 performance share plan outcomes (audited) Shares awarded Shares vesting including dividends Value of vested shares, Feb/ Mar 2021 Impact of share price changea Bernard Looney 158,690b 126,134 £350,652 -£228,991 Murray Auchinclossc 77,958b 62,124 $275,934 -$111,497 Bob Dudleyc 1,395,600 410,922 $1,566,298 -$962,923 Brian Gilvary 696,705 227,337 £618,357 -£430,217 a These values reflect the impact of the reduction in share price since grant related to the number of shares that vest, excluding dividend equivalents. b
Share grants under the GSVP are made at 50% of maximum, not at 100% of maximum as for the EDIP. c Bob Dudley and Murray Auchincloss’s awards were granted in respect of American depositary shares (ADSs). The numbers in this table reflect calculated equivalents in ordinary shares. One ADS equates to six ordinary shares. The value of vested shares reflects the share price changes all shareholders have experienced over the three-year period. For this 2018-20 award cycle, the original grant was calculated based on ordinary share and American depositary share (ADS) prices of £5.00 and $39.85 respectively, while the values at vesting were £2.78/£2.72 (on 16 and 19 February respectively), and $22.87/$26.65 (on 19 February and 10 March respectively). Consequently, the share price fall has reduced the initial face value of these awards by approximately 45% for ordinary shares, by 33% for Murray Auchincloss’s ADSs,
and by 43% for Bob Dudley’s ADSs. The committee has made no discretionary adjustment to vesting outcomes related to these share price changes.
112 bp Annual Report and Form 20-F 2020 2018-20 performance shares scorecard (audited) Relative total shareholder return 12.5% Return on average capital employed 0% Strategic process 20.0% Formulaic vesting 32.5% Financial 12.5% 5.0% 0% 5.0% 5.0% These measures were set under the terms of our 2017 policy Measures Outcome Weighting at maximum Threshold performance Maximum performance See page 39 for more on our key performance indicators. + + = Return on average capital employed Market-led growth in the downstream
Gas power and renewables trading and marketing growth Relative total shareholder return Formulaic vesting 32.5% Underpin: Committee review of absolute returns, long-term safety and environmental performance, low carbon and climate change considerations: No adjustment Final vesting after committee judgement 32.5% Venturing and low carbon across multiple fronts Third 7.375% 50% 5% 30% 5% 5% First 11.5% Outcome Outcome 12.5% 20.0% Third Formulaic 32.5% 2.6% Strategic progress 5.0% Growing gas and advantaged oil in the upstream 5% Qualitative and quantitative assessment by the committee. No numeric scale for vesting outcome. See page 111 Directors’ remuneration report continued
113
Corporate governance bp Annual Report and Form 20-F 2020 Executive directors’ pay for 2020 Single figure table – executive directors (audited) Bernard Looney CEO since 5 Feb 2020 (thousand) Murray Auchincloss CFO since 1 July 2020 (thousand) Bob Dudley CEO to 4 Feb (thousand) Brian Gilvary CFO to 30 June (thousand) 2020 2020 2020 2019 2020 2019 Salary £1,181 £348 $170 $1,854 £395 £785 Benefits £26 £8 $18 $84 £41 £59 Retirement benefits – – $0 $544 £0 £0 Cash in lieu of retirement benefits £177 £52 – – £115 £252 Annual bonus, cash – – – $1,408 – £600 Annual bonus, deferred (as detailed on page 107) – – – $1,408 – £600 Performance shares (as detailed on page 107) £351
£215 – $8,039a – £2,787a Discontinued plans – – – – – £1,529a Total remunerationb £1,735 £623 $188 $13,336 £552 £6,612 Total fixed remuneration £1,384 £408 $188 $2,481 £552 £1,095 Total variable remuneration £351 £215 $0 $10,855 £0 £5,517 Please refer to the overview section below for additional detail, except where noted otherwise. a The amounts reported for 2019 have been adjusted to include the vesting of additional dividends on 5 November 2020 at the market price of £2.03 for ordinary shares and $15.83 for ADSs. See the performance shares table on page 111, and the deferred shares table on page 120, for further details on these awards. b Due to rounding, the totals do not agree exactly with the sum of their component parts. Overview of
single figure outcomes (audited) Bernard Looney and Murray Auchincloss started in their roles as CEO and CFO on 5 February and 1 July 2020 respectively. Accordingly, the values shown in the single figure table represent remuneration outcomes from the time of their appointment to the board only. Similarly, because Bob Dudley and Brian Gilvary stepped down on 4 February and 30 June respectively, their 2020 remuneration values relate only to their part-years of service as executive directors. Payments received after they stepped down from their position are included in the payments to past directors section on page 122. Salary and benefits Bernard Looney’s salary was £1,300,000 from appointment. The amount reported above is before his 20% mental health charitable contribution. Murray Auchincloss’s salary was £695,000 from appointment. Bob Dudley’s salary remained at $1,854,000 until his exit on 31 March 2020.
Brian Gilvary’s salary was unchanged at £790,500 until his exit on 30 June 2020. All executive directors received car-related benefits, assistance with tax return preparation, security assistance, insurance and medical benefits. 2020 annual bonus The committee concluded that there should be no bonus for 2020 as the plan was unaffordable. There were no other contributing factors leading us to this decision. 2018-20 performance shares Please refer to page 112 for details of the performance measures, targets and outcomes for these performance shares. Retirement benefits From their appointment as executive directors, Bernard Looney and Murray Auchincloss ceased to receive any retirement benefits for their service, but receive a cash allowance fixed at 15% of salary in line with the majority of similarly situated employees. They may choose to direct these allowances into retirement plans at their sole discretion, and the amounts are therefore identified
as cash in lieu of retirement benefits on the single figure table. Bob Dudley was provided with pension benefits and retirement savings through a combination of tax-qualified and non-qualified benefit plans. His normal retirement age is 60. The BP Supplemental Executive Retirement Benefit Plan (SERB) is a non-qualified defined benefit pension plan which provides a proportion of earnings for each year of service. In 2020 his accrued defined benefit pension did not increase, and the amount included in the single figure table is therefore zero. The BP Employee Savings Plan (ESP) is a US tax-qualified defined contribution plan to which both Bob and bp contributed. The BP Excess Compensation (Savings) Plan (ECSP) is a non-qualified, unfunded, retirement savings plan to which bp notionally contributed 7% of base salary above the annual IRS limit. In 2020 Bob made contributions to the ESP totalling $28,500 and bp made matching contributions to the ESP, and notional
contributions to the ECSP, totalling $32,445. However, investment losses in his unfunded ECSP account (aggregating the unfunded arrangements relating to his overall service with bp and TNK-BP) exceeded these contributions, hence the amount included in the single figure table is zero.
114 bp Annual Report and Form 20-F 2020 Brian Gilvary was provided with retirement benefits through a combination of tax-qualified and non-qualified plans for service to 31 March 2011, but linked to his final salary. In line with terms offered to UK employees employed prior to 2010 (or before 2014 in the North Sea) Brian was a member of the BP Pension Scheme (bpPS), a UK final salary
defined benefit pension plan. Pension benefits accrued in excess of the individual lifetime tax allowance set by legislation were provided to Brian via a non-qualified, unfunded pension arrangement designed to mirror the design of the approved bpPS. His normal retirement age is 60, although due to his long service, benefits accrued before 1 December 2006 may be paid unreduced from age 55 with bp’s consent. Brian received no salary increase in 2020, hence his interests in these retirement benefits did not increase and the amount included in the single figure table is therefore zero. For service after 31 March 2011 Brian received a cash allowance in lieu of further accrual. This was set at 30% of salary to 30 May, then 25% of salary to 30 June 2020, and the amount has been separately identified in the single figure table. Discontinued plans In accordance with 2014 policy, Brian Gilvary compulsorily deferred one third of his 2015 annual bonus and
received a matching award of bp shares. Both the deferred and matching awards were subject to a three-year performance period which ended on 31 December 2018, however Brian voluntarily requested that the committee delay the performance assessment and vesting of the 2015 matching award for two years, to 31 December 2020. The committee considered operational and financial performance and reviewed safety and environmental sustainability performance over the 2016-20 period, seeking input from the strategy and sustainability committee on safety and sustainability measures. The committee concluded that safety performance continues to show improvement, with safety embedded in the culture of the organization and supporting strong operational and financial performance. The committee concluded that this award should vest in full. Because this award vested post-employment, the value is included in the payments to past directors statement on page 122, with further
details available in the deferred shares table on page 120. Bob Dudley has previously requested that the committee delay the performance assessment and vesting of all his deferred and matching awards under the 2014 policy. Following the committee’s conclusion that the original safety and environmental sustainability conditions have been met, these awards will vest one year after his retirement, and the value will be reported in the payments to past directors statement in our 2021 report. History of chief executive officer remuneration Year Chief executive officer Total remuneration thousanda Annual bonus % of maximum Performance shares % of maximum 2011 Bob Dudley $8,439 66.7 16.7 2012 Bob Dudley $9,609 64.9 0 2013 Bob Dudley $15,086 88.0 45.5 2014 Bob Dudley $16,390 73.3 63.8 2015 Bob Dudley $19,376 100.0 74.3 2016 Bob Dudley $11,904 61.0 40.0 2017 Bob Dudley $15,108 71.5 70.0 2018 Bob Dudley $15,253 40.5 80.0 2019 Bob Dudley $13,336 67.5 71.2
2020b Bob Dudley $188 0 32.5 Bernard Looney £1,735 0 32.5 a Total remuneration figures include share vesting outcomes. b 2020 figures show remuneration for the periods of qualifying service as CEO during 2020, as per the single figure values on page 113. Directors’ remuneration report continued
115 Corporate governance bp Annual Report and Form 20-F 2020 Wider workforce in 2020 Workforce experience During 2020 the committee has continued to receive and review information on pay outcomes and processes for our wider workforce in order to take account of wider workforce pay and conditions when setting executive remuneration, and to consider alignment
between pay structures. As part of this review we carried out a programme of engagement with a diverse range of employees from different parts of the workforce from the front line to corporate office and covering new joiners, employees with long tenure in the organization, and employees of different gender and nationality. The topics discussed addressed bp’s new purpose and ambition, and how this aligns with the organization’s reward programmes. Our enquiries ranged from success in attracting and retaining talent, employee preferences in how pay is delivered, the make-up of the reward package, and programmes to support international mobility. A recurring theme was the desire for flexibility, with employees wanting to be empowered to make their own choices about how they work and how they are remunerated for their work. Overall we continue to observe well-balanced and structured approaches to reward. Although these approaches vary by business
area and location, the core offering for the majority of our workforce is summarized in the table on page 116. We also find that financial reward is complemented with strong emphasis on maintaining a supportive and inclusive working environment. For instance, our commitment to family-friendly leave policies; recognition as a top global employer in Stonewall’s list of the best multinational employers for LGBT+ staff; and scoring 100% for a fourth consecutive year in the Human Rights Campaign’s 2021 Corporate Equality Index, which measures adoption of non-discrimination policies, equitable benefits for LGBT+ employees and families, and supporting an inclusive culture and corporate social responsibility. We are also pleased to confirm that bp is now accredited by the Living Wage Foundation as a real living wage employer in the UK. This ensures all colleagues in our UK businesses and at company-owned sites are paid at least the real living
wage and we are now reviewing the position across other bp countries. We apply the insights we gain from engaging with the workforce to challenge leadership generally and to make sure we think about remuneration holistically, not just with regard to those leaders whose pay is within our remit. This has been more relevant than ever through a year in which the COVID-19 pandemic has had such a significant impact on our people and business. Wider workforce salary increases were postponed at the normal salary review date 1 April 2020; from 1 October 2020 staff below our senior leadership level did receive increases. Salaries remained frozen for senior leaders (other than promotions) throughout 2020. Over half of our global workforce participates in an annual cash bonus plan and for 2020 the plan was intended to pay an incentive based equally on individual performance and bp performance. However, as reported in my opening letter, the committee and CEO both concluded
that there should be no bonus for 2020 as the plan was unaffordable, and this outcome applies equally to our executive directors, leadership team, and those of our wider workforce who participate in the annual bonus plan. These decisions reflect our principle of consistency for all those rewarded under our common template. Note, however, that a limited number of employees, such as those with specific contractual rights or who work in parts of the business with different remuneration models, have received bonus payments for 2020. Looking forward, we have reviewed the role of share plans offered to employees with a view to understanding the extent to which these plans align our wider workforce with bp’s purpose, particularly whether employees are personally invested in the new ambition and able to share in success. This review has led to our support for a ‘one off’ equity grant to every bp employee in 2021, vesting in 2025, reflecting
our belief in sharing success broadly while aligning employees’ longer-term interests with all shareholders. We have also devoted time to examine the support provided for employee health and wellbeing, to gain a better understanding of how these aspects of policy support the organization’s culture and encourage appropriate behaviours. This is an ongoing study and we will have more to report next year. Turning to non-discrimination matters, we understand the sharp interest that exists in disclosures of gender and ethnicity pay gaps. Having reviewed the gender pay gap reports of the last several years we are satisfied that reward processes and decisions are designed and managed to effectively avoid bias, and that reported pay gaps relate in the main to differences in gender representation across the pay hierarchy. We therefore conclude that the narrative accompanying our pay gap reporting is better reflected within bp’s diversity
and inclusion reporting, rather than remuneration reporting. With this in mind, and because bp has committed to annual diversity and inclusion reporting, we will leave additional commentary to that publication, which is expected to be available on the company’s website bp.com next month.
116 bp Annual Report and Form 20-F 2020 Summary of remuneration structure for employees below the board Element Policy features for the wider workforce Comparison with executive
director remuneration Salary Our salary is the basis for a competitive total reward package for all employees, and we conduct an annual salary review for all non-unionized employees. As we determine salaries in this review, we take account of comparable pay rates at other relevant employers, the skills, knowledge and experience of each individual, relativity to peers within bp, individual performance, and the overall budget we set for each country. In setting the budget each year, we assess how employee pay is currently positioned relative to market rates, forecasts of any further market increases, and business context related to such things as growth plans, workforce turnover and affordability. The salaries of our executive directors and executive leadership form the basis of their total remuneration, and we review these salaries annually. The primary purpose of the review is to stay aligned with relevant market comparators. We intend to keep increases
within the salary review budgets set for our wider workforce, except in specific circumstances. Pensions and benefits We offer market-aligned benefits packages reflecting normal practice in each country in which we operate. Where appropriate, and subject to scale, we offer significant elements of personal benefit choice to our employees. Other than the addition of security-related benefits, our executive director benefit packages are broadly aligned with other employees who joined bp in the same country at the same time. Under our 2020 remuneration policy pension benefits have been sharply reduced for our new executive directors, who receive a cash-in-lieu of pension allowance set at 15% of salary. Their previously accrued defined benefit calculations are capped on pre-appointment salary service. Annual bonus Over half of our global workforce participate in an annual cash bonus plan that multiplies a target bonus amount by a performance factor in the
range 0 to 2. For 2021, the performance factor will reflect bp performance alone, placing emphasis on aligning individual efforts to the shared goals of the company at this critical stage of our transition. We operate different bonus plans for those distinct parts of our business where remuneration models in the market are markedly different, such as our trading and marketing businesses. Annual bonus for executive directors is directly related to the same group performance measures and outcomes as the wider workforce. Performance shares We operate a performance share plan with three-year vesting for employees from our professional entry level and above. Operation varies based on seniority in three broad tiers: group leaders (approximately 300); senior leaders (approximately 4,000); and all other professional employees (approximately 32,000 potential participants, of
whom 20% will participate). Vesting is subject to group performance outcomes for the group leader population only. Performance shares for our executive directors are assessed using the same group performance scorecard used for the group leader performance shares. Directors’ remuneration report continued
117 Corporate governance bp Annual Report and Form 20-F 2020 Chief executive officer to employee pay ratio This is our second year reporting the CEO pay ratio following the requirements introduced in 2018. As last year, we have selected option A as our reporting basis, being the most accurate approach available. The employees included in these calculations
were employed by the group on 31 December 2020 and pay and benefits values were determined with reference to the financial year ending 31 December 2020. We confirm that no broadly applicable components of pay have been omitted and, where necessary, full-time equivalent pay has been calculated by simple engrossment of part year values. Our analysis this year covers more than 14,000 UK employees, 45% of whom work in our retail sites. Employee values reflect the zero bonus outcome for the majority of employees, and the delayed salary review date, from 1 April to 1 October. Given the succession of CEO in 2020, these employee values are compared against the sum of total pay values, per the single figure table on page 113, for Bernard Looney and Bob Dudley. Year Method 25th percentile: pay ratio, total pay and benefits, (salary) 50th percentile: pay ratio, total pay and benefits, (salary) 75th percentile: pay ratio, total pay and benefits, (salary)
2019 Option A 543:1 £19,108 (£18,845) 188:1 £55,071 (£38,800) 82:1 £126,085 (£74,200) 2020 Option A 99:1 £18,984 (£18,984) 40:1 £46,933 (£29,040) 19:1 £98,546 (£80,475) Bob Dudley’s pay has been converted from US dollars at 0.77907 for 2020. The 2019 ratio is as originally reported. The sharp reduction in 50th percentile ratio from 188:1 to 40:1 reflects the fact that CEO remuneration is more heavily weighted to variable pay which reduces in years of weaker performance such as 2020. This is a natural reason for volatility in pay ratio reporting from year to year, and illustrates one of the challenges in commenting on whether any given year’s pay ratio is appropriate. Our considered view as to appropriateness is that the policies for our CEO, and for the wider workforce, are both fit for purpose and that they deliver
pay outcomes appropriate to the circumstance of the year. Thus differentials reflect both the relative contributions made at different levels in our hierarchy, and the nature of the year in question. Taken in the round with all of the insights we have gained into pay policies and practices, we remain satisfied that pay outcomes, and the ratios derived from them, are as they should be. In particular we note that as well as being paid at least the real living wage, our UK employees also benefit from the significant intangible value of working in an inclusive and caring enterprise that is not reflected in pay ratio analyses. Percentage change comparisons: Directors’ remuneration versus employees In the table below, values in column ‘a’ represent the percentage change in salary and fees; values in column ‘b’ represent the percentage change in taxable benefits; and values in column ‘c’ represent
the percentage change in bonus outcomes for performance periods in respect of each financial year. The employee percentages shown represent the change in median employee pay. This compares the median BP p.l.c. employee on 31 December of the relevant financial year, with the median BP p.l.c. employee on 31 December of the preceding financial year, in each case ranked based on the total of salary, benefits and bonus. For the chair and non-executive directors, the decline in the value of taxable benefits largely relates to the sharp drop in business travel arising from pandemic-related travel restrictions. 2020 v 2019 a b c Employees 0% 0% -100% Bernard Looney – – – Murray Auchincloss – – – Bob Dudley 0% -5% -100% Brian Gilvary 1% 13% -100% Nils Andersen -7% -46% n/a Dame Alison Carnwath -4% -94% n/a Pamela Daley -15% -92% n/a Sir Ian Davis -14% -81% n/a Professor Dame Ann Dowling -4% -96% n/a Helge Lund
(Chair) 0% -74% n/a Melody Meyer 9% -77% n/a Tushar Morzaria – – n/a Brendan Nelson -7% -71% n/a Paula Rosput Reynolds 2% -92% n/a Sir John Sawers -3% -83% n/a Bob Dudley, Brian Gilvary and Nils Andersen resigned during 2020, therefore, other than for one-time items, their 2020 pay has been annualised for comparison. Bernard Looney, Murray Auchincloss and Tushar Morzaria were appointed on the board in 2020 and therefore no comparison to 2019 is available. Relative importance of spend on pay ($ million) 20202019 9,844 6,340 Distributions to shareholders 20202019 9,872 9,878 Remuneration paid to all employees 20202019 15,238 12,034 Capital investment
118
bp Annual Report and Form 20-F 2020 Stewardship and executive director interests We believe that our executive directors should have a material interest in the company, both during their tenure and after they leave bp. Our 2020 remuneration policy therefore requires the CEO and other executive directors to build personal shareholdings of five times salary and four and half times salary, respectively, within five years of their appointment. They are expected to maintain those shareholding levels for two years post employment. Directors’ shareholdings (audited) The table below details the personal shareholdings of each current and former executive director. Both Bob Dudley and Brian Gilvary significantly exceed their post-employment shareholding commitment. Bernard Looney and Murray Auchincloss are building towards the policy requirement that applies five years from their
dates of appointment, 5 February and 1 July 2020 respectively. These figures include all beneficial and non-beneficial ownership of shares of bp (or calculated equivalents) that have been disclosed to the company. Director Ordinary shares or equivalents at 1 Jan 2020 Ordinary shares or equivalents at 31 Dec 2020 Changes from 31 Dec 2020 to 2 Mar 2021 Ordinary shares or equivalents at 2 Mar 2021 Appointment date Value of current shareholding Multiple of salary achieved Bernard Looney – 331,711 212,228 543,939 5 February 2020 £1,615,499a 1.24x Murray Auchincloss – 139,525 2,010 141,535 1 July 2020 £420,359a 0.60x Bob Dudleyb 4,592,208 – – – October 2010 – – Brian Gilvaryb 2,593,708 – – – January 2012 – – a Based on ordinary share
price at 2 March 2021 of £2.97. b Bob Dudley and Brian Gilvary resigned on 4 February and 30 June 2020 respectively. These current and former executive directors have additional interests in restricted and performance shares, and Bob and Brian have various interests in deferred bonus shares. These additional share interests are shown in aggregate, and by plan, in the tables below. For performance shares, the figures reflect maximum possible vesting levels (excluding the addition of reinvested dividends) even though the actual number of shares that vest will depend on the extent to which performance conditions are satisfied. Aggregated interests, all plans (audited) Directora Unvested ordinary shares or equivalents at 1 Jan 2020 Unvested ordinary shares or equivalents at 31 Dec 2020 Changes from 31 Dec 2020 to 2 Mar 2021 Unvested ordinary shares or equivalents at 2 Mar 2021 Bernard Looney – 3,193,599 -530,370 2,663,229 Murray
Auchincloss – 1,581,899 -2,755 1,579,144 Bob Dudley 6,639,882 5,296,740 – – Brian Gilvary 2,905,764 2,060,135 – – a Bernard Looney was appointed as CEO on 5 February and Murray Auchincloss was appointed as CFO on 1 July 2020, Bob Dudley and Brian Gilvary resigned on 4 February and 30 June 2020 respectively. Directors’ remuneration report continued
119 Corporate governance bp Annual Report and Form 20-F 2020 Performance shares (audited) Performance period Date of award of performance shares Share element interests Interests vested in 2020 and 2021 Potential maximum performance sharesa Number of ordinary shares vested
Vesting date Face value of awardc, £ At 1 Jan 2020 Awarded 2020 At 31 Dec 2020 Bernard Looney 2018-20b 20 Mar 2018 317,380 – 317,380 126,134 16 Feb 2021 2019-21b 25 Mar 2019 335,920 – 335,920 – – 1,840,842 2020-22d 11 Aug 2020 – 2,076,677 2,076,677 – – 6,396,165 Murray Auchincloss 2018-20be 20 Mar 2018 155,916 – 155,916 62,124 10 Mar 2021 2019-21be 25 Mar 2019 156,468 – 156,468 – – 857,445 2020-22d 11 Aug 2020 – 999,201 999,201 – – 3,077,539 Bob Dudleye 2017-19f 19 May 2017 1,571,628 – – 1,358,334 18 Feb 2020 – 2018-20g 22 May 2018 1,395,600 – 1,395,600 410,922 19 Feb 2021 – 2019-21 19 Feb 2019 1,340,766 – 1,340,766 – – 7,199,913 Brian Gilvary 2017-19f 19 May 2017 722,093 – – 623,242 18 Feb 2020 – 2018-20g 22
May 2018 696,705 – 696,705 227,337 19 Feb 2021 – 2019-21 19 Feb 2019 654,315 – 654,315 – – 3,513,672 a For awards under the 2017-19 plan, performance conditions are measured 50% on TSR relative to Chevron, ExxonMobil, Shell and Total (‘comparator companies’) over three years, 30% on ROACE based on performance in 2019, and 20% on strategic progress assessed over the performance period. For awards under the 2018-2020 plans, performance conditions are measured on the same basis as the 2017-2019 plan, except ROACE which will be based on performance in the last two years of the performance period (i.e. 2019 and 2020). For awards under the 2019-2021 plans, performance conditions are measured 50% on TSR relative to the comparator companies over three years, 20% ROACE averaged over the full performance period, and 30% on strategic progress assessed over the performance period. Each performance period
ends on 31 December of the third year. b Awards granted under the Group Share Value Plan (GSVP) prior to appointment as executive directors (disclosed share interests reflect maximum vesting, though under this plan awards are granted at 50% of maximum). Represents vesting of shares at the end of the performance period based on performance achieved under rules of the plan and includes reinvested dividends on the shares vested. Bernard Looney’s 2018-20 award vested on 16 February 2021, when the market price was £2.78 for each share, and Murray Auchincloss’s award vested on 10 March 2021 when the market price for each ADS was $26.65. The amounts reported as 2020 income on the single figure table are therefore £351k for Bernard Looney and $275k (£215k) for Murray Auchincloss. c Face values have been calculated using market prices of ordinary shares at closing on the dates of award, as follows; £5.37 on 19 February
2019; £5.48 on 25 March 2019; and £3.08 on 11 August 2020. d Minimum vesting under these awards (below threshold performance) is 0%. At the lowest performance outcome that would yield an above-zero score on each measure, vesting would be 10% of maximum. e These awards were received in the form of ADSs. The above numbers reflect calculated equivalents in ordinary shares. One ADS is equivalent to six ordinary shares. f Represents vesting of shares at the end of the performance period based on performance achieved under rules of the plan and includes reinvested dividends on the shares vested. This 2017-2019 award vested on 18 February 2020, when the market price was £4.54 for each ordinary share, and $36.09 for each ADS. Reinvested dividends were delivered on 5 November 2020, when the market price was £2.03 for each ordinary share, and $15.83 for each ADS. The adjusted amounts reported as 2019 income on the single figure table
are therefore $8.039 million for Bob Dudley, and £2.787 million for Brian Gilvary. g Represents vestings of shares at the end of the performance period based on performance achieved under rules of the plan, pro-rated for time served, and includes reinvested dividends on the shares vested. This 2018-2020 award vested on 19 February 2021, when the market price was £2.72 for each share, and $22.87 for each ADS. As they were received post-employment, the value of these vested shares are included in the payments to past directors section on page 122. Restricted shares (audited) Restricted period Date of award of restricted shares Share element interests Face value of awardc, £ Number of restricted shares At 1 Jan 2020 Awarded 2020 At 31 Dec 2020 Bernard Looney 2016-20a 15 Mar 2016 75,000 – 75,000 256,500 2018-20a 20 Mar 2018 104,577 – 104,577 485,237 2018-20b 20 Mar 2018 137,990 – 137,990 640,274 2019-21b
25 Mar 2019 146,055 – 146,055 800,381 Murray Auchincloss 2018-20a 20 Mar 2018 43,170 – 43,170 200,308 2018-22a 20 Mar 2018 43,170 – 43,170 200,308 2018-20b 20 Mar 2018 86,616 – 86,616 401,898 2018-20d 20 Mar 2018 2,755 – 2,755 12,783 2019-21d 25 Mar 2019 2,835 – 2,835 15,536 2019-21b 25 Mar 2019 86,928 – 86,928 476,365 2020-22d 28 Aug 2020 – 4,840 4,840 12,778 a Awards made under the Restricted Share Plan II prior to appointment as a director. b Awards made under the Individual Share Value Plan prior to appointment as a director. Awards under this plan were granted at 100% of salary. c Face values have been calculated using market prices of ordinary shares at closing on the dates of award, as follows; £3.42 on 15 March 2016; £4.64 on 20 March 2018; £5.48 on 25 March 2019; £2.64 on 28 August 2020. d Interests of person closely associated with Murray
Auchincloss.
120 bp Annual Report and Form 20-F 2020 Deferred sharesa (audited) Bonus year Type Performance period Date of award of deferred shares Deferred share element interests Interests vested in 2020 and 2021Potential maximum deferred shares At 1 Jan 2020 Awarded 2020 At 31 Dec 2020 Number of ordinary shares vested Vesting date Face value of the awardd, £ Bob Dudleybc 2014 Comp 2015-17 11 Feb 2015 147,054 – 147,054 – – 655,861 Vol 2015-17 11 Feb 2015 147,054 – 147,054 – – 655,861 Mat 2015-17 11 Feb 2015 294,108 – 294,108 – – 1,311,722 2015 Comp 2016-18 4
Mar 2016 275,892 – 275,892 – – 1,015,283 Vol 2016-18 4 Mar 2016 275,892 – 275,892 – – 1,015,283 Mat 2016-18 4 Mar 2016 551,784 – 551,784 – – 2,030,565 2016 Comp 2017-19 19 May 2017 147,642 – 147,642 – – 696,870 Mat 2017-19 19 May 2017 147,642 – 147,642 – – 696,870 2017 Comp 2018-20 22 May 2018 226,236 – 226,236 – – 1,330,268 2018 Comp 2019-21 19 Feb 2019 118,584 – 118,584 – – 636,796 2019 Comp 2020-22 18 Feb 2020 – 228,486 228,486 – – 1,046,466 Brian Gilvary 2014 Mat 2015-17 11 Feb 2015 176,576 – – 253,223e 18 Feb 20 – 2015 Mat 2016-18 4 Mar 2016 318,042 – 318,042 402,227f 19 Feb 21 – 2016 Comp 2017-19 19 May 2017 73,070 – – 88,577e 18 Feb 20 – Matg 2017-19
19 May 2017 73,070 – 73,070 – – 344,890 2017 Comp 2018-20 22 May 2018 127,457 – 127,457 153,562h 19 Feb 21 – 2018 Comp 2019-21 19 Feb 2019 64,436 – 64,436 – – 346,021 2019 Comp 2020-22 18 Feb 2020 – 126,110 126,110 – – 577,584 a Since 2010, vesting of the deferred shares has been subject to a safety and environmental sustainability hurdle. If the committee assesses that there has been a material deterioration in safety and environmental performance, or there have been major incidents, either of which reveal underlying weaknesses in safety and environmental management, then it may conclude that shares should vest only in part, or not at all. In reaching its conclusion, the committee obtains advice from the SAS committee. There is no identified minimum vesting threshold level. ‘Comp’ denotes compulsory deferral, ‘Vol’
denotes voluntary deferral, and ‘Mat’ denotes matching awards. b Bob Dudley received awards in the form of ADSs. The above numbers reflect calculated equivalents in ordinary shares. One ADS is equivalent to six ordinary shares. c Bob Dudley has voluntarily agreed to defer vesting of these awards until one year post employment. d Face values have been calculated using market prices of ordinary shares on the dates of award, as follows; £4.46 on 11 February 2015; £3.68 on 4 March 2016; £4.72 on 19 May 2017; £5.88 on 22 May 2018; £5.37 on 19 February 2019; £4.58 on 18 February 2020. e Represents vestings of shares at the end of the deferral period and includes reinvested dividends on the shares vested. The market price of each share used to determine the total value at vesting on 18 February 2020 was £4.54. The additional reinvested dividend shares were delivered on 5 November 2020,
at a market price of £2.03. The adjusted amount reported as 2019 income on the single figure table is therefore £1.529 million. f Represents vesting of shares made at the end of the deferral period, prorated for 54 months’ service out of 60 months’ vesting period, and includes reinvested dividends thereon. The market price of each share used to determine the total value at vesting on 19 February 2021 was £2.72. As they were received post-employment, the values of these vested shares are included in the payments to past directors section on page 122. g Brian Gilvary has voluntarily agreed to defer vesting of this 2016 matching award to at least one year post employment. h In line with the 2017 policy, these compulsory deferrals of Bob and Brian’s 2017 bonus were included in the single figure of total remuneration reported for 2017 and therefore the values of these shares are not included as payments to past
directors. In common with many of our UK employees, Bernard Looney holds options under the bp group save as you earn (SAYE) scheme as shown below. These options are not subject to performance conditions. Share interests in share option plans (audited) Director Option type At 1 Jan 2020 Granted Exercised At 31 Dec 2020a Option price Market price at date of exercise Date from which first exercisable Expiry date Bernard Looney SAYE 6,024 – – 6,024 £2.54 – 01 Sep 2025 28 Feb 2026 Murray Auchincloss SAYEb – 3,614 – 3,614 £2.54 – 01 Sep 2023 28 Feb 2024 Brian Gilvary BP 2011c 400,000 – – 400,000 £3.72 – 07 Sep 2014 07 Sep 2021 Brian Gilvary SAYEd 2,064 – – – £4.36 – 01 Sep 2022 28 Feb 2023 a The closing market price of an ordinary share on 31 December 2020 was £2.55. During 2020 the highest
market price was £5.04, and the lowest market price was £1.93. b Interest of person closely associated with Murray Auchincloss. c The BP 2011 plan – these options were granted to Brian Gilvary prior to his appointment as a director and are not subject to performance conditions. d Brian Gilvary closed his save as you earn contract, and therefore these options lapsed, on 18 June 2020. Bernard Looney, Murray Auchincloss, Bob Dudley and Brian Gilvary have no interests in bp preference shares, debentures or option plans (other than as listed above), and none have interests in shares or loan stock of any subsidiary company. No directors or other leadership team members own more than 1% of the ordinary shares in issue. At 2 March 2021, our directors and leadership team members collectively held interests of 5,294,828 ordinary shares or their calculated
equivalents, 10,204,082 restricted share units (with or without conditions) or their calculated equivalents, 3,075,878 performance shares or their calculated equivalents and 1,580,380 options over ordinary shares or their calculated equivalents, under bp group share option schemes. Directors’ remuneration report continued
121 Corporate governance bp Annual Report and Form 20-F 2020 Post employment share ownership interests Bob Dudley and Brian Gilvary have, and will continue to retain, significant interests in bp post employment. Under our 2017 policy, they gave their personal commitment as executive directors to maintain actual holdings equivalent to two
and a half times salary for two years post employment. Their ongoing interests in share awards under group plans which remain subject to vesting and/or holding periods materially exceed the two and a half times salary threshold, and thus guarantee that they will continue to meet their minimum shareholding commitment. Although we instituted a formal post employment share ownership requirement as part of our 2020 policy, given the foregoing, we have not modified the requirements for these former executives. Chair and non-executive director outcomes and interests The remuneration policy for the chair and non-executive directors (NEDs) was approved at the 2020 AGM and implemented during 2020. Fee structure The table below shows the fee structure for the chair and NEDs, per our 2020 policy. The chair is not eligible for committee chairmanship and membership fees or intercontinental travel allowance. Fees £ thousand Chair 785 Senior independent directora 120
Board member 90 Audit, geopolitical, remuneration and SAS committees chairmanship feesb 30 Committee membership feec 20 Intercontinental travel allowance 5 a The senior independent director is eligible for committee chairmanship fees and intercontinental travel allowance plus any committee membership fees. b Committee chairs do not receive an additional membership fee for the committee they chair. c For members of the audit, geopolitical, SAS and remuneration committees. As disclosed in our 2019 report, in early 2020 a revised fee structure was adopted for implementation with effect from 1 June 2020. The implementation of that revised fee structure was postponed on account of the COVID-19 pandemic and actions taken by bp in response. With effect from 1 January 2021, a fee for membership of the people and governance committee has been introduced given the increased time commitment associated with the expanded responsibilities of this committee. The fee is in line with
other committee membership fees. The senior independent director has waived her entitlement to this committee membership fee. The geopolitical advisory council was constituted with effect from 1 January 2021. Fees of £10,000 and £15,000 are payable for membership of and chairing the council, respectively. The fee structure for 2021 remains otherwise unchanged and the board will review the situation again during the year. The table below shows the fees paid and applicable benefits for the year ended 31 December 2020. Benefits include travel and other expenses relating to the attendance at board and other meetings. As chair throughout 2020, Helge Lund had the use of a fully maintained office for company business, a car and driver, and security advice in London. Benefits values have been grossed up using a tax rate of 45%, where relevant, as an estimation of tax due. 2020 remuneration (audited) Fees Benefits Totala £ thousand 2020 2019
2020 2019 2020 2019 Nils Andersenb 38 161 1 11 39 172 Dame Alison Carnwathb 110 115 2 33 112 148 Pamela Daley 140 164 3 37 143 201 Sir Ian Davisb 143 165 1 5 143 170 Professor Dame Ann Dowlingc 135 140 0 3 135 143 Helge Lund (Chair) 785 785 25 95 810 880 Melody Meyer 166 152 4 16 170 168 Tushar Morzariab 37 – 0 – 37 – Brendan Nelson 140 150 3 11 143 161 Paula Rosput Reynolds 174 170 3 36 177 206 Sir John Sawers 140 145 0 1 140 146 a Due to rounding, the totals may not agree exactly with the sum of the component parts. b Nils Andersen resigned on 18 March 2020. Sir Ian Davis resigned on 30 December 2020. Tushar Morzaria was appointed on 1 September 2020. Dame Alison Carnwath resigned on 14 January 2021. c Fee includes £25,000 for chairing and being a member of the bp technology advisory council.
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bp Annual Report and Form 20-F 2020 Chair and non-executive directors’ interests (audited) The figures below include all the beneficial and non-beneficial interests of the chair and each non-executive director of the company in shares of bp (or calculated equivalents) that have been disclosed according to the disclosure guidance and transparency rules in the Financial Conduct Authority handbook (‘the DTRs’) as at the applicable dates. Our policy, shown on page 126, includes a shareholding guideline encouraging non-executive directors to establish a holding in bp shares of the equivalent value of one year’s base fee. Ordinary shares or equivalents at 1 Jan 2020 Ordinary shares or equivalents at 31 Dec 2020 Changes from 31 Dec 2020 to 2 Mar 2021 Ordinary shares or equivalents at 2 Mar 2021 Value of current shareholdinga % of policy achieved
Nils Andersenb 125,000 – – – – – Dame Alison Carnwathb 17,700 17,700 – – – – Pamela Daley 17,592c 40,332c 0 40,332c $166,504 144% Sir Ian Davisb 52,671 – – – – – Professor Dame Ann Dowling 22,320 22,320 0 22,320 £66,290 74% Helge Lund (Chair) 600,000 600,000 0 600,000 £1,782,000 227% Melody Meyer 20,646c 20,646c 0 20,646c $85,234 74% Tushar Morzariab – 36,276 0 36,276 £107,740 120% Brendan Nelsond 21,626 21,626 0 21,626 £64,229 71% Paula Rosput Reynolds 73,200c 73,200c 0 73,200c $302,194 262% Karen Richardsonb – – – 10,746c $44,363 38% Sir John Sawers 15,506 23,116 0 23,116 £68,655 76% Dr Johannes Teyssenb – – – 20,000 £59,400 66% a Based on share and ADS prices at 2 March 2021 of £2.97 and $24.77.
b Nils Andersen and Sir Ian Davis resigned on 18 March and 30 December 2020 respectively. Tushar Morzaria appointed on 1 September 2020. Karen Richardson and Dr Johannes Teyssen appointed on 1 January 2021. Dame Alison Carnwath resigned on 14 January 2021. c Held as ADSs. d Brendan Nelson’s 31 December 2019 shareholding was incorrectly shown as 11,040 shares, rather than 21,626 shares, in our 2019 report. Payments for loss of office (audited) Brian Gilvary received a payment in lieu of notice of £447,950 relating to the part of his 12-month notice period that followed his retirement on 30 June 2020. As detailed on page 120, Bob Dudley deferred the vesting of various deferred and matching share awards, related to annual bonus outcomes from 2014 to 2019, until at least one year post retirement. Of these, awards under the 2014 policy (for bonus years 2014, 2015 and 2016) were not included in the single figures of total remuneration, therefore the
values of these awards will be disclosed in the payments to past directors section of the relevant annual report following vesting. Similarly, Brian Gilvary deferred the vesting of his 2016 matching share award until at least one year post retirement. The value of this award will be disclosed in the payments to past directors section of the relevant annual report following vesting. Payments to past directors (audited) Since leaving employment, Bob Dudley and Brian Gilvary have received shares upon vesting of the awards listed below: (1) Bob Dudley received 410,922 shares on vesting of his 2018-20 performance share award on 19 February 2021. Based on a share price of $22.78 this vesting was valued at $1,566,298. This award reflects the 32.5% vesting outcome, and has been pro-rated for 27 months’ service through the three-year performance period. (2) Brian Gilvary received 227,337 shares on vesting of his 2018-20 performance share award on 19 February 2021.
Based on a share price of £2.72 this vesting was valued at £618,357. This award reflects the 32.5% vesting outcome, and has been pro-rated for 30 months’ service through the three-year performance period. (3) Brian Gilvary received 402,227 shares on vesting of his 2015 matching award on 19 February 2021. Based on a share price of £2.72 this vesting was valued at £1,094,057. This award has been pro-rated for 54 months’ service through the five-year vesting period. Bob Dudley was also provided with post-employment medical benefits amounting to $14,359, ongoing car and driver benefits in the UK, amounting to $44,429, and relocation benefits to assist his repatriation to the US, amounting to $47,186. We made no other payments within the scope of the disclosure requirements to any past director of bp during 2020 (we have no de minimis threshold for such disclosures). Directors’ remuneration report
continued
123 Corporate governance bp Annual Report and Form 20-F 2020 Other disclosures Historical TSR performance 2019 2020201820172016201520142013201220112010 £0 £50 £100 £150 £200 £250 BP FTSE 100 This graph shows the growth in value of hypothetical £100 investments in BP p.l.c. ordinary shares, and in the FTSE 100 Index (of which bp is a constituent), over 10 years from 31 December 2010 to 31 December 2020. Independence and advice The board considers all committee members to be independent with no personal financial interest, other than as shareholders, in the committee’s decisions.
Further detail on the activities of the committee, advice received, and shareholder engagement is set out in the remuneration committee report on page 105. During 2020 Ben Mathews, who was employed by the company and reported to the chair of the board, acted as secretary to the remuneration committee. The committee also received advice on various matters relating to the remuneration of executive directors and senior management from Helmut Schuster, former EVP, group human resources, Kerry Dryburgh, EVP, people and culture (from 1 July 2020) and Ashok Pillai, SVP, reward and wellbeing. PricewaterhouseCoopers LLP (‘PwC’) continued to provide independent advice to the committee in 2020, following its appointment as independent advisor to the committee in September 2017, following a competitive tender process. None of PwC’s consultants advising
the committee have any connection with the company’s directors. PwC advice included, for example, support with remuneration benchmarking and updates on market practice. PwC is a member of the Remuneration Consulting Group and, as such, operates under the code of conduct in relation to executive remuneration consulting in the UK. The committee is satisfied that the advice received is objective and independent. Freshfields Bruckhaus Deringer LLP (‘Freshfields’) provided legal advice on specific compliance matters to the committee. PwC and Freshfields provide other advice in their respective areas to the group. During the year, PwC provided bp with services including: subsidiary company secretarial support; digital and IT services; low carbon strategy consulting; internal audit subject matter expertise and trading transformation. Total fees or
other charges (based on an hourly rate) for the provision of remuneration advice to the committee in 2020 (save in respect of legal advice) were £110,262 to PwC. Considerations related to the Corporate Governance Code When setting the 2020 policy, the committee concluded that the scorecard- based approach to setting targets and measuring outcomes provides great clarity in our ability to engage transparently with shareholders and the wider workforce on remuneration. Thus, bp continues to operate a simple structure of market-aligned salary with annual and three-year performance- based incentives. Risks are managed through careful setting of performance measures and targets, and broad options to apply committee discretion in assessing outcomes, such as the decision to pay no annual bonus for 2020. These are complemented with robust malus and clawback measures. Remuneration outcomes are predictable, as shown in the scenario charts of the 2020 policy,
and proportional by virtue of the challenging performance levels required to achieve target pay outcomes. Through material weighting in measures related to safety, sustainability and strategy, as shown on page 109, remuneration aligns closely with bp’s culture, as expressed through our purpose and ambition. Shareholder engagement Throughout 2020 we continued to discuss remuneration policy and approach with many of our largest shareholders, as well as investor representative bodies. We plan to continue this dialogue in 2021, as we consider issues and make decisions related to the implementation of our remuneration policy for 2021 and beyond. The table below shows the votes on the report for the last three years. AGM directors’ remuneration report vote results Year % vote ‘for’ % vote ‘against’ Votes withheld 2020 96.05% 3.95% 67,623,825 2019 95.93% 4.07% 337,586,814 2018 96.42% 3.58% 42,741,541
The remuneration policy was approved by shareholders at the 2020 AGM last May. The votes on the policy are shown below. 2020 AGM directors’ remuneration policy vote results Year % vote ‘for’ % vote ‘against’ Votes withheld 2020 96.58% 3.42% 65,652,222 External appointments The board supports executive directors taking up appointments outside the company to broaden their knowledge and experience. Each executive director is permitted to retain any fee from their external appointments. Such external appointments are subject to agreement by the chair and reported to the board. Any external appointment must not conflict with a director’s duties and commitments to bp. Details of appointments as non-executive directors of publicly listed companies during 2020 are shown below. Director Appointee company Additional position held
at appointee company Total fees Bernard Looney Rosnefta Director 0 Murray Auchincloss Aker BP ASAa Director 0 Bob Dudley Rosnefta Director 0 Brian Gilvary Air Liquide SA Non-executive director Eur 38,375 Brian Gilvary Barclays plc Non-executive director £47,500 a Held as a result of the company’s shareholdings in Rosneft and Aker BP ASA.
124 bp Annual Report and Form 20-F 2020 Policy implementation for 2021 The table below shows how the remuneration policy approved by shareholders at the 2020 AGM will be implemented in 2021, alongside a summary of key features.
For the full remuneration policy, please go to bp.com/remuneration Salary and benefits To provide fixed remuneration to reflect the scale and complexity of both the business and the role, and to be competitive with the external market. When setting salaries, the committee considers practice in other oil and gas majors as well as European and US companies of a similar size, geographic spread and business dynamic to bp. Percentage increases for executive directors will not exceed increases for the broader employee population, other than in specific circumstances identified by the committee (e.g. in response to a substantial change in responsibilities). Bernard Looney’s salary will increase by 2.75% to £1,335,750 following the 2021 AGM. Murray Auchincloss’s salary will increase by 8% to £750,500 following the 2021 AGM. This compares to an increase in excess of 4% to our UK salaried staff effective from 1 April, our
annual salary review date. Benefits will remain unchanged for 2021 and include car-related provisions (or cash in lieu), security assistance, insurance and medical cover. Retirement benefits Executive directors normally participate in the company retirement plans that operate in their home country. New appointees from within the bp group retain previously accrued benefits. For their service as a director, retirement benefits will be no more than the median provision offered to the wider workforce in the UK. For future appointments, the committee will carefully review any retirement benefits to be granted to a new director, taking account of retirement policies across the wider group and any arrangements currently in place. Bernard and Murray are deferred members of final salary pension plans related to their service prior to appointment as executive directors, but now
receive a cash allowance in lieu of retirement benefits. Bernard’s cash allowance will be unchanged at 15%, and he accrues no further value under his deferred pension. Murray’s cash allowance will be unchanged at 15%, and he accrues no further value under his US deferred pension. Annual bonus Bonus is measured against an annual scorecard. The committee holds discretion to choose the specific measures and the relative weightings adopted in the annual scorecard, to reflect the annual plan as agreed with the board. Numeric scales are set for each measure, to score outcomes relative to targets. A scorecard outcome of 1.0 reflects the target outcome, and half of the maximum outcome. Target bonus is 112.5% of salary, and maximum bonus is 225% of salary. Half of the bonus for each year is paid in cash, and half is delivered as a deferred share award vesting in three years. For our 2021 bonus, our scorecard will be reweighted to safety
(15%), environment (15%), operational (20%) and financial (50%). Please see scorecard measures on page 125 for detail. Awards are subject to malus and clawback provisions described on page 125. Performance shares Performance shares are granted with a three-year performance period, measured against scorecard. The committee holds discretion to choose the specific measures and the relative weightings adopted in the scorecard, to ensure they are focused on the near-term priorities for delivering the bp strategy in the interests of shareholders. Annual grants are 500% of salary for the CEO, and 450% of salary for any other executive director. Awards will vest in proportion to the outcomes measured through the performance scorecard, subject to any adjustment by the committee. For our 2021-23 cycle, 20% each for rTSR, ROACE, and EBIDA CAGR, and 40% for strategic progress. Please see scorecard measures on page 125 for detail. The 2021-23 awards will be granted
in June 2021, based on the average closing share price over the 90 days preceding our 2021 AGM. Awards are subject to malus and clawback provisions described on page 125. Directors’ remuneration report continued
125 Corporate governance bp Annual Report and Form 20-F 2020 Shareholding requirement CEO to build a shareholding of at least five times salary, and other executive directors four and a half times salary, within five years of appointment. Executive directors are required to maintain at least that minimum level for at least two years post employment. Bernard and Murray have not yet reached five years since appointment, and are therefore building
the share interests towards the level required by policy. Malus and clawback Malus provisions may apply where there is: a material safety or environmental failure; an incorrect award outcome due to miscalculation or incorrect information; a restatement due to financial reporting failure or misstatement of audited results; material misconduct; or other exceptional circumstances that the committee considers similar in nature. Clawback provisions may apply where there is: an incorrect outcome due to miscalculation or incorrect information; a restatement due to financial reporting failure or misstatement of audited results; or material misconduct. Committee flexibility The committee holds discretion to adjust performance measures and weightings, and to revise the peer group for the rTSR measure. This discretion allows appropriate re-alignment, throughout the policy term, for changes in the annual plan and for the anticipated evolution of the low carbon business
environment. The committee also holds discretion in determining the outcomes for annual bonus and performance shares, allowing them to take broad views on alignment with shareholder experience, environmental, societal and other relevant considerations. The committee has committed to an ongoing review of the outcomes of 2020-22 performance shares to ensure there is no windfall gain related to share price appreciation following market turmoil around the time the awards were granted. Safety 15% Tier 1/2 process safety Relative TSR 20% Environment 15% Sustainable emissions reductions ROACE 20% Operational performance 20% bp-operated plant reliability and refining availability (10%) Margin share from convenience and electrification (10%) Growth (EBIDA CAGR) 20% Financial performance 50% Free cash flow (25%) Cumulative cash cost reductions (25%) Strategic progress 40% Deliver value through a resilient and focused hydrocarbon business Demonstrate a track record,
scale and value in low carbon electricity and energy Accelerate growth in convenience and mobility Performance measures for incentive plans commencing in 2021 Annual bonus (weighting as % of maximum) Performance shares (weighting as % of maximum) Underpin: To take into account safety outcomes prior to determining final vesting percentage Discretion: To reflect shareholder experience, environment, societal and other inputs Robust malus and clawback
126 bp Annual Report and Form 20-F 2020 Policy table – non-executive directors Non-executive chair Fees Approach Remuneration is in the form of cash fees, payable monthly. The level and structure of the chair’s
remuneration will primarily be compared against UK best practice. Operation and opportunity The quantum and structure of the non-executive chair’s remuneration is reviewed annually by the remuneration committee, which makes a recommendation to the board. Benefits and expenses Approach The chair is provided with support and reasonable travelling expenses. Operation and opportunity The chair is provided with an office and full-time secretarial and administrative support in London and a contribution to an office and secretarial support in his home country as appropriate. A car and the use of a driver is provided in London, together with security assistance. All reasonable travelling and other expenses (including any relevant tax) incurred in carrying out his duties are reimbursed. Non-executive directors Fees Approach Remuneration is in the form of cash fees, payable monthly. Remuneration practice is consistent with recognized best practice standards for
non-executive directors’ remuneration and, as a UK-listed company, the level and structure of non-executive directors’ remuneration will primarily be compared against UK best practice. Additional fees may be payable to reflect additional board responsibilities, for example, committee chairmanship and membership and for the role of senior independent director. Operation and opportunity The level and structure of non-executive directors’ remuneration is reviewed by the chair, the CEO and the company secretary who make a recommendation to the board. Non-executive directors do not vote on their own remuneration. Remuneration for non-executive directors is reviewed annually. Intercontinental allowance Approach Non-executive directors receive an allowance to reflect the global nature of the
company’s business. The intercontinental travel allowance is payable for the purpose of attending board or committee meetings or site visits. Operation and opportunity The allowance is paid in cash following each event of intercontinental travel. Benefits and expenses Approach Non-executive directors are provided with administrative support and reasonable travelling expenses. Professional fees are reimbursed in the form of cash, payable following the provision of advice and assistance. Operation and opportunity Non-executive directors are reimbursed for all reasonable travelling and subsistence expenses (including any relevant tax) incurred in carrying out their duties. The reimbursement of professional fees incurred by non-executive directors based outside the UK in connection with advice and assistance on UK tax compliance matters. Shareholding guidelines Approach Non-executive directors are encouraged to establish a holding in bp shares of the
equivalent value of one year’s base fee. This directors’ remuneration report was approved by the board and signed on its behalf by Ben J. S. Mathews, company secretary, on 22 March 2021. Directors’ remuneration report continued
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Consolidated financial statements of the bp group
Report
of Independent Registered Public Accounting Firm
To the shareholders and board of directors of BP p.l.c.
Opinion on the financial statements
We have audited the accompanying consolidated group balance sheets of BP p.l.c. and subsidiaries (together the company) as of 31 December 2020 and 2019, the related consolidated group income statements, group statements of comprehensive income, group statements of changes in equity, and group cash flow statements, for each of the three years in the period ended 31 December 2020, and the related notes (collectively referred to as the 'financial statements'). In our opinion, the financial statements present fairly, in all material
respects, the financial position of the company as of 31 December 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended 31 December 2020, in conformity with International Financial Reporting Standards (IFRS) as adopted by the European Union and IFRS as issued by the International Accounting Standards Board.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the company's internal control over financial reporting as of 31 December 2020, based on criteria established in the UK Financial Reporting Council’s Guidance on Risk Management, Internal Control and Related Financial and Business Reporting
relating to internal control over financial reporting and our report dated 22 March 2021 expressed an unqualified opinion on the group's internal control over financial reporting.
Basis for opinion
These financial statements are the responsibility of the group's management. Our responsibility is to express an opinion on the group's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the group in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are
free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate
to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
1.Property, plant and equipment (PP&E) assets – Impairment of upstream oil and gas – Notes 1, 4 and 12 to the financial statements
Critical Audit Matter Description
The group balance sheet at 31 December 2020 includes PP&E of $115 billion, of which $74 billion is oil and gas properties within the upstream segment.
Management’s
best estimate of oil and gas price assumptions for value–in-use impairment tests were revised downwards during 2020 compared to the prior year assumptions, as set out in Note 1 on page 161. The downward revisions reflect an expectation that the aftermath of the COVID-19 pandemic will accelerate the pace of transition to a lower carbon economy and energy system. Given the significance of these revisions, management tested all upstream CGUs for impairment.
Management recorded $12.9 billion of pre-tax upstream CGU impairment charges, in large part due to the oil and gas prices revisions detailed above, and $0.1 billion of pre-tax upstream CGU impairment reversals. Further information has been provided in Note 1 on page 160, Note 4 on page 179 and Note 12 on page 189.
Through our audit risk assessment procedures, we have a identified a critical audit matter in respect of PP&E impairment
principally due to the following three key management estimates in management’s determination of the level of impairment charge and/or reversal to record.
•Oil and gas prices - bp’s oil and gas price assumptions have a significant impact on many CGU impairment assessments performed across the upstream segment, and are inherently uncertain. As noted above, the estimation of future prices is subject to increased uncertainty given climate change, the global energy transition and the impact of COVID-19. There is a risk that management do not forecast reasonable “best estimate” oil and gas price forecasts when assessing CGUs for impairment, leading to material misstatements. These price assumptions are highly judgmental and are pervasive inputs to most upstream impairment tests, such that any misstatements would also aggregate. There is also a risk that management’s oil and
gas price related disclosures are not reasonable.
•Discount rates - Given the long timeframes involved, certain CGU impairment assessments are sensitive to the discount rate applied. Discount rates should reflect the return required by the market and the risks inherent in the cash flows being discounted. There is a risk that management do not assume reasonable discount rates, adjusted as applicable for country risks and relevant tax rates, leading to material misstatements. Determining a reasonable discount rate is highly judgmental and, consistent with price assumptions above, the discount rate assumption is also a pervasive input across upstream impairment tests, before adjustments for asset specific risks and tax rates, such that any misstatements would also aggregate.
•Reserves and resources estimates
- A key input to certain CGU impairment assessments is the oil and gas production forecast, which is based on underlying reserves estimates and field specific development assumptions. Certain CGU production forecasts include specific risk adjusted resource volumes, in addition to proved or probable reserves estimates, that are inherently less certain than reserves; and assumptions related to these volumes can be particularly judgemental. There is a risk that material misstatements could arise from unreasonable production forecasts for individually material CGUs and/or from the aggregation of systematic flaws in bp’s reserves and resources estimation policies across the segment.
150
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Annual Report and Form 20-F 2020
Financial statements
We identified certain individual CGUs with a total carrying value of $32.1 billion which we determined would be most at risk of material impairment charges or reversals as a result of a plausible change in the key assumptions, particularly oil and gas price and discount rate assumptions.
We also identified CGUs with a further $16.0 billion of combined carrying value which were less sensitive as they would be potentially at risk, in aggregate, to a material impairment or reversal by
a plausible change in some or all of the key assumptions.
Further information regarding these sensitivities is given in Note 1 on page 167.
How the Critical Audit Matter was addressed in the Audit
We tested management’s key internal controls over the estimation of oil and gas prices, discount rates and reserve and resources estimates, as well as key internal controls over the performance of the impairment assessments where we identified audit risks. In addition, we conducted the following substantive procedures.
Oil and gas prices
•We independently developed a reasonable range of forecasts based on external data obtained, against which we compared management’s oil and gas price assumptions in order to challenge whether they are reasonable.
•In
developing this range we obtained a variety of reputable and reliable third party forecasts, peer information and other relevant market data.
•In challenging management's price assumptions, we considered the extent to which they and each of the forecast pricing scenarios obtained from third parties reflect the impact of lower oil and gas demand due to climate change, the energy transition and COVID-19.
•We specifically analysed third party forecasts stated as being, or interpreted by us as being, consistent with achieving the Paris 2°C Goal and considered whether they presented contradictory audit evidence.
•We challenged management’s disclosures in Notes 1 and 4 including in relation to the sensitivity of oil and gas price assumptions to reduced demand scenarios whether
due to climate change or other reasons.
Discount rates
•We independently evaluated bp’s discount rates used in impairment tests with input from Deloitte valuation specialists, against relevant third party market and peer data.
•We assessed whether specific country risks and tax adjustments were reasonably reflected in bp’s discount rates.
•We challenged management’s disclosures in Notes 1 and 4 including in relation to the sensitivity of discount rate assumptions.
Reserves and resources estimates
With the assistance of Deloitte oil and gas reserves specialists we:
•assessed bp’s
reserves and resources estimation methods and policies;
•assessed, guided by our risk assessment, how these policies had been applied to a sample of bp’s reserves and resources estimates which included those that we judged to represent the greatest risk of material misstatement;
•read a sample of reports provided by management’s external reserves experts and assessed the scope of work and findings of these third parties;
•assessed the competence, capability and objectivity of bp’s internal and external reserve experts; through understanding their relevant professional qualifications and experience.
•compared the production forecasts used in the impairment tests with management’s approved reserves and
resources estimates, those estimates having been subjected to the controls that we had tested; and
•performed a retrospective assessment to check for indications of estimation bias over time
Other procedures
•We challenged management’s CGU determinations, and considered whether there was any contradictory evidence present.
•We validated that bp’s impairment methodology was acceptable under IFRS and tested the integrity and mechanical accuracy of certain impairment models based on our risk assessment.
•We challenged other CGU specific valuation input assumptions, including but not limited to material cost and tax forecasts, by comparing forecasts to approved
internal and third party budgets, development plans, independent expectations and historical actuals.
•Where relevant, we assessed management’s historical forecasting accuracy and whether the estimates had been determined and applied on a consistent basis across the group.
2.Intangible assets – Write-off of Exploration and Appraisal (E&A) assets, included within 'intangible assets' within the Group balance sheet – Notes 1, 8 and 15 to the financial statements
Critical Audit Matter Description
The group capitalises E&A expenditure on a project-by-project basis in line with IFRS 6 'Exploration for and Evaluation of Mineral Resources'. At 31 December 2020, $4.1 billion of E&A expenditure was carried on the group balance sheet.
E&A
activity carries inherent risk and a significant proportion of projects fail, requiring the write-off or impairment of the related capitalised costs when the relevant criteria in IFRS 6 and bp’s accounting policy are met.
Furthermore, similar to upstream PP&E assets discussed above, E&A assets are also potentially exposed to climate change, the global energy transition, and COVID-19, in that a greater number of E&A projects may not proceed as a consequence of lower forecast future demand and oil and gas pricing, lower appetite by management and the board to allocate capital to certain projects, and/or increased objections from stakeholders to the development of certain projects.
As a result of bp’s revised strategy announced in 2020, including a reduced capital frame, a net-zero carbon ambition and a decision not to explore in new countries, and reflecting lower oil
and gas price assumptions, management identified IFRS 6 impairment indicators at a number of upstream’s largest E&A assets during the year. This led to management recording $9.9 billion of pre-tax E&A write-offs and impairments during 2020, detailed further in Notes 1 and 8 on pages 164 and 184.
The determination of when E&A costs should be written off or impaired, or retained on the balance sheet as E&A assets, can be complex and require significant judgement from management in assessing this. There is a risk that certain capitalised E&A costs are written off or impaired when they
bp
Annual Report and Form 20-F 2020
151
should not have been, due to inappropriate and/or inconsistent application of IFRS 6 impairment criteria and bp’s accounting policy, leading to material misstatements. There is also a risk that E&A costs remain capitalised on the balance sheet which ought to have been written off or impaired, leading to material misstatements.
We identified a critical audit matter for the individually material E&A write-offs recorded in 2020, specifically the Kaskida and Tigris (Paleogene) licenses that were the largest part of the $2.5 billion Gulf of Mexico write downs, the Terre de Grace oil sands project that was the largest part of the $2.5 billion Canada
write downs and the three licenses that were the largest part of the $2.1 billion Brazil write-downs. We also identified higher risks in relation to certain other 2020 E&A write-offs and impairments recorded; and higher risks at certain assets within the $4.4 billion of E&A costs that remain capitalised under IFRS 6 at 31 December 2020.
How the Critical Audit Matter was addressed in the Audit
We obtained an understanding of the group’s E&A assessment processes and tested management’s key internal controls. This included the key internal controls operated by management for the key decisions taken as a result of bp’s new strategy, which when taken together with the lower forecast oil and gas prices, led to a large portion of the material write-offs and impairments recorded during 2020.
We challenged management’s key E&A
judgements, with regards to the impairment criteria of IFRS 6 and bp’s accounting policy. We corroborated key internal and external evidence relevant to significant write-offs and the assets that remained on the balance sheet. This included analysing evidence of future E&A plans, budgets and capital allocation decisions, assessing management’s key accounting judgement papers, holding discussions to challenge top level operational and finance management on the key judgements taken and reading meeting minutes, license documentation and evidence of active dialogue with partners and regulators including negotiations to renew licences or modify key terms, and external press releases.
For E&A assets that were written off or impaired by management in 2020, including in particular those based upon decisions taken in line with management’s
new strategy, we considered whether evidence (and potential contradictory evidence) about activity in the year, future budgeted expenditure and exploration/appraisal plans, including plans and expectations for licence relinquishment or retention, were consistent with the decisions taken by management to write-off or impair these assets.
We assessed whether management had consistently applied IFRS 6 and bp’s accounting policy to impairment assessments, taking account of in year judgements and historical look back considerations, and the relevant facts and circumstances of specific E&A assets.
When considering capital allocation decision making, we considered whether the progression of any projects that remain on the balance sheet would be inconsistent with elements of bp’s new strategy and in particular its net zero carbon commitments.
3.Accounting
for structured commodity transactions (SCTs) within the trading and shipping (T&S) function and the valuation of other Level 3 financial instruments, where fraud risks may arise in revenue recognition (potentially impacting all financial statement accounts, in particular finance debt) - Notes 1, 20, 22, 29 and 30 to the financial statements
Critical Audit Matter Description
In the normal course of business, T&S enters into a variety of transactions for delivering value across the group’s supply chain. The nature of these transactions requires significant audit effort to be directed towards challenging management’s valuation estimates or the adopted accounting treatment.
We have undertaken an analysis of the portfolio composition and revisited our risk assessment throughout the year focussing particularly on the impact of COVID-19
on the valuation assertion. This process has provided us with a deeper understanding of the impact of market volatility, demand destruction and the changing structure of the markets in which bp operates.
Accounting for structured commodity transactions:
T&S may also enter into a variety of transactions which we refer to as SCTs. We generally consider a SCT to be an arrangement having one of the following features:
•Two or more counterparties with non-standard contractual terms;
•Multiple commodity-based transactions; and/or
•Contractual arrangements entered into in contemplation of each other.
SCTs are often long-dated, can have a
significant multi-year financial impact, and may require the use of complex valuation models or unobservable inputs when determining their fair value, in which case they will be classified as level 3 financial instruments under IFRS 13, ‘Fair Value Measurement’.
Accounting for SCTs is typically complex and involves significant judgment, as these transactions often feature multiple elements that will have a material impact on the presentation and disclosure of these transactions in the financial statements and on key performance measures, including in particular the classification of liabilities as finance debt. Accordingly, we have identified the accounting for SCTs as a critical audit matter.
Level 3 financial instruments:
Unlike other financial instruments whose values or inputs are readily observable and therefore more easily independently
corroborated, there are certain transactions for which the valuation is inherently more subjective due to the use of either complex valuation models and/or unobservable inputs. These instruments are classified as level 3 financial assets or liabilities. This degree of subjectivity also gives rise to a risk of potential fraud through management incorporating bias in determining fair values. Accordingly, we have identified these as a significant audit risk.
As at 31 December 2020, the group’s total financial assets and liabilities measured at fair value were $12.7 billion and $8.4 billion, of which level 3 derivative financial assets were $6.4 billion and level 3 derivative financial liabilities were $5.3 billion.
How the Critical Audit Matter was addressed in the Audit
Accounting for SCTs
For structured
commodity transactions, we:
•Tested controls related to the accounting for complex transactions.
•Developed an understanding of the commercial rationale of the transactions through reading transaction documents and executed agreements, and discussions with management.
•Performed a detailed accounting analysis for a sample of SCTs involving significant day one profits, deferred working capital arrangements, offtake arrangements and/or commitments. We confirmed that any day one profits were appropriately deferred.
152
bp
Annual Report and Form 20-F 2020
Financial statements
For SCTs which were identified during 2018 and 2019 and that continue through 2020, we have refreshed our assessment in 2020 taking account of any amendments to the contracts.
To assess the appropriateness of the accounting treatment of SCTs, we embedded technical accounting specialists within the audit team.
Level 3 financial instruments:
To
address the complexities associated with auditing the value of level 3 financial instruments, the engagement team included valuation specialists having significant quantitative and modelling expertise to assist in performing our audit procedures. Our valuation audit procedures included the following control and substantive procedures:
•We tested the group’s valuation controls including the:
–Model certification control, which is designed to review a model’s theoretical soundness and the appropriateness of its valuation methodology; and
–Independent price verification control, which is designed to review the appropriateness of valuation inputs that are not observable and are significant to the financial instrument’s valuation.
•We
performed substantive valuation testing procedures at interim and year-end balance sheet date, including:
–Comparing management’s input assumptions against the expected assumptions of other market participants and observable market data;
–Evaluating management’s valuation methodologies against standard valuation practice and analysing whether a consistent framework is applied across the business period over period; and
–Engaging a Deloitte valuations specialist to challenge models, develop fair value estimates and verify consistency in management’s modelling and input assumptions throughout the year. Our independent estimates were established using independently sourced inputs (where available). We evaluated whether the differences between our independent estimates and
management’s estimates were within a reasonable range. In situations where we utilised management’s inputs, these were compared to external data sources to determine whether they were reasonable.
The first accounting period we audited was the 12 month period ended 31 December 2018.
bp
Annual Report and Form 20-F 2020
153
Consolidated financial statements of the bp group
Report of Independent Registered Public Accounting Firm
To the shareholders and board of directors of BP p.l.c.
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of BP p.l.c. and subsidiaries (the
Company) as at 31 December 2020, based on the criteria established in the UK Financial Reporting Council’s Guidance on Risk Management, Internal Control and Related Financial and Business Reporting relating to internal control over financial reporting (UK FRC Guidance). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as at 31 December 2020, based on the criteria established in the UK FRC Guidance.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as at and for the year ended 31 December 2020, of the Company and our report dated 22 March 2021, expressed an unqualified opinion
on those consolidated financial statements.
Basis for opinion
The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s report on internal control over financial reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities
laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and limitations of internal control over financial reporting
A
company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance
with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Earnings
from joint ventures – after interest and tax
16
(i302)
i576
i897
Earnings
from associates – after interest and tax
17
(i101)
i2,681
i2,856
Interest
and other income
7
i663
i769
i773
Gains
on sale of businesses and fixed assets
4
i2,874
i193
i456
Total
revenues and other income
i183,500
i282,616
i303,738
Purchases
19
i132,104
i209,672
i229,878
Production
and manufacturing expenses
i22,494
i21,815
i23,005
Production
and similar taxes
5
i695
i1,547
i1,536
Depreciation,
depletion and amortization
5
i14,889
i17,780
i15,457
Impairment
and losses on sale of businesses and fixed assets
4
i14,381
i8,075
i860
Exploration
expense
8
i10,280
i964
i1,445
Distribution
and administration expenses
i10,397
i11,057
i12,179
Profit
(loss) before interest and taxation
(i21,740)
i11,706
i19,378
Finance
costs
7
i3,115
i3,489
i2,528
Net
finance expense relating to pensions and other post-retirement benefits
24
i33
i63
i127
Profit
(loss) before taxation
(i24,888)
i8,154
i16,723
Taxation
9
(i4,159)
i3,964
i7,145
Profit
(loss) for the year
(i20,729)
i4,190
i9,578
Attributable
to
bp shareholders
(i20,305)
i4,026
i9,383
Non-controlling
interests
(i424)
i164
i195
(i20,729)
i4,190
i9,578
Earnings
per share
Profit (loss) for the year attributable to bp shareholders
Per ordinary share (cents)
Basic
11
(i100.42)
i19.84
i46.98
Diluted
11
(i100.42)
i19.73
i46.67
Per
ADS (dollars)
Basic
11
(i6.03)
i1.19
i2.82
Diluted
11
(i6.03)
i1.18
i2.80
bp
Annual Report and Form 20-F 2020
155
Group statement of comprehensive incomea
For the year ended 31 December
$
million
Note
2020
2019
2018
Profit (loss) for the year
(i20,729)
i4,190
i9,578
Other
comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences
(i1,843)
i1,538
(i3,771)
Exchange
(gains) losses on translation of foreign operations reclassified to gain or loss on sale of businesses and fixed assets
(i353)
i880
i—
Cash
flow hedges marked to market
30
i78
(i100)
(i126)
Cash
flow hedges reclassified to the income statement
30
(i37)
i106
i120
Costs
of hedging marked to market
30
i42
(i4)
(i244)
Costs
of hedging reclassified to the income statement
30
i22
i57
i58
Share
of items relating to equity-accounted entities, net of tax
16, 17
i312
i82
i417
Income
tax relating to items that may be reclassified
9
i66
(i70)
i4
(i1,713)
i2,489
(i3,542)
Items
that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset
24
i170
i328
i2,317
Cash
flow hedges that will subsequently be transferred to the balance sheet
30
i7
(i3)
(i37)
Income
tax relating to items that will not be reclassified
9
(i105)
(i157)
(i718)
i72
i168
i1,562
Other
comprehensive income
(i1,641)
i2,657
(i1,980)
Total
comprehensive income
(i22,370)
i6,847
i7,598
Attributable
to
bp shareholders
(i21,983)
i6,674
i7,444
Non-controlling
interests
(i387)
i173
i154
(i22,370)
i6,847
i7,598
a
See Note 32 for further information.
156
bp Annual Report and Form 20-F 2020
Financial
statements
Group statement of changes in equitya
$
million
Share capital and capital reserves
Treasury shares
Foreign currency translation reserve
Fair value reserves
Profit and loss account
bp shareholders' equity
Non-controlling interests
Total equity
Hybrid bonds
Other interest
At
1 January 2020
i46,525
(i14,412)
(i6,495)
(i912)
i73,706
i98,412
—
i2,296
i100,708
Profit
for the year
—
—
—
—
(i20,305)
(i20,305)
i256
(i680)
(i20,729)
Other
comprehensive income
—
—
(i2,224)
i98
i448
(i1,678)
—
i37
(i1,641)
Total
comprehensive income
—
—
(i2,224)
i98
(i19,857)
(i21,983)
i256
(i643)
(i22,370)
Dividendsb
—
—
—
—
(i6,367)
(i6,367)
—
(i238)
(i6,605)
Cash
flow hedges transferred to the balance sheet, net of tax
—
—
—
i6
—
i6
—
—
i6
Repurchase
of ordinary share capital
—
—
—
—
(i776)
(i776)
—
—
(i776)
Share-based
payments, net of tax
i176
i1,188
—
—
(i638)
i726
—
—
i726
Share
of equity-accounted entities’ changes in equity, net of tax
—
—
—
—
i1,341
i1,341
—
—
i1,341
Issue
of perpetual hybrid bonds
—
—
—
—
(i48)
(i48)
i11,909
—
i11,861
Payments
on perpetual hybrid bonds
—
—
—
—
—
—
(i89)
—
(i89)
Tax
on issue of perpetual hybrid bonds
—
—
—
—
i3
i3
—
—
i3
Transactions
involving non-controlling interests, net of tax
—
—
—
—
(i64)
(i64)
—
i827
i763
At
31 December 2020
i46,701
(i13,224)
(i8,719)
(i808)
i47,300
i71,250
i12,076
i2,242
i85,568
At
31 December 2018
i46,352
(i15,767)
(i8,902)
(i987)
i78,748
i99,444
—
i2,104
i101,548
Adjustment
on adoption of IFRS 16, net of tax
—
—
—
—
(i329)
(i329)
—
(i1)
(i330)
At
1 January 2019
i46,352
(i15,767)
(i8,902)
(i987)
i78,419
i99,115
—
i2,103
i101,218
Profit
for the year
—
—
—
—
i4,026
i4,026
—
i164
i4,190
Other
comprehensive income
—
—
i2,407
i52
i189
i2,648
—
i9
i2,657
Total
comprehensive income
—
—
i2,407
i52
i4,215
i6,674
—
i173
i6,847
Dividendsb
—
—
—
—
(i6,929)
(i6,929)
—
(i213)
(i7,142)
Cash
flow hedges transferred to the balance sheet, net of tax
—
—
—
i23
—
i23
—
—
i23
Repurchase
of ordinary share capital
—
—
—
—
(i1,511)
(i1,511)
—
—
(i1,511)
Share-based
payments, net of tax
i173
i1,355
—
—
(i809)
i719
—
—
i719
Share
of equity-accounted entities’ changes in equity, net of tax
—
—
—
—
i5
i5
—
—
i5
Transactions
involving non-controlling interests, net of tax
—
—
—
—
i316
i316
—
i233
i549
At
31 December 2019
ii46,525/
(i14,412)
(i6,495)
(i912)
i73,706
i98,412
—
i2,296
i100,708
At
31 December 2017
i46,122
(i16,958)
(i5,156)
(i743)
i75,226
i98,491
—
i1,913
i100,404
Adjustment
on adoption of IFRS 9, net of tax
—
—
—
(i54)
(i126)
(i180)
—
—
(i180)
At
1 January 2018
i46,122
(i16,958)
(i5,156)
(i797)
i75,100
i98,311
—
i1,913
i100,224
Profit
for the year
—
—
—
—
i9,383
i9,383
—
i195
i9,578
Other
comprehensive income
—
—
(i3,746)
(i216)
i2,023
(i1,939)
—
(i41)
(i1,980)
Total
comprehensive income
—
—
(i3,746)
(i216)
i11,406
i7,444
—
i154
i7,598
Dividendsb
—
—
—
—
(i6,699)
(i6,699)
—
(i170)
(i6,869)
Cash
flow hedges transferred to the balance sheet, net of tax
—
—
—
i26
—
i26
—
—
i26
Repurchase
of ordinary share capital
—
—
—
—
(i355)
(i355)
—
—
(i355)
Share-based
payments, net of tax
i230
i1,191
—
—
(i718)
i703
—
—
i703
Share
of equity-accounted entities’ changes in equity, net of tax
—
—
—
—
i14
i14
—
—
i14
Transactions
involving non-controlling interests, net of tax
—
—
—
—
i—
i—
—
i207
i207
At
31 December 2018
i46,352
(i15,767)
(i8,902)
(i987)
i78,748
i99,444
—
i2,104
i101,548
a
See Note 32 for further information.
b See Note 10 for further information.
bp Annual Report and Form 20-F 2020
157
Group
balance sheet
At 31 December
$ million
Note
2020
2019
Non-current assets
Property,
plant and equipment
12
i114,836
i132,642
Goodwill
14
i12,480
i11,868
Intangible
assets
15
i6,093
i15,539
Investments
in joint ventures
16
i8,362
i9,991
Investments
in associates
17
i18,975
i20,334
Other
investments
18
i2,746
i1,276
Fixed
assets
i163,492
i191,650
Loans
i840
i630
Trade
and other receivables
20
i4,351
i2,147
Derivative
financial instruments
30
i9,755
i6,314
Prepayments
i533
i781
Deferred
tax assets
9
i7,744
i4,560
Defined
benefit pension plan surpluses
24
i7,957
i7,053
i194,672
i213,135
Current
assets
Loans
i458
i339
Inventories
19
i16,873
i20,880
Trade
and other receivables
20
i17,948
i24,442
Derivative
financial instruments
30
i2,992
i4,153
Prepayments
i1,269
i857
Current
tax receivable
i672
i1,282
Other
investments
18
i333
i169
Cash
and cash equivalents
25
i31,111
i22,472
i71,656
i74,594
Assets
classified as held for sale
2
i1,326
i7,465
i72,982
i82,059
Total
assets
i267,654
i295,194
Current
liabilities
Trade and other payables
22
i36,014
i46,829
Derivative
financial instruments
30
i2,998
i3,261
Accruals
i4,650
i5,066
Lease
liabilities
28
i1,933
i2,067
Finance
debt
26
i9,359
i10,487
Current
tax payable
i1,038
i2,039
Provisions
23
i3,761
i2,453
i59,753
i72,202
Liabilities
directly associated with assets classified as held for sale
2
i46
i1,393
i59,799
i73,595
Non-current
liabilities
Other payables
22
i12,112
i12,626
Derivative
financial instruments
30
i5,404
i5,537
Accruals
i852
i996
Lease
liabilities
28
i7,329
i7,655
Finance
debt
26
i63,305
i57,237
Deferred
tax liabilities
9
i6,831
i9,750
Provisions
23
i17,200
i18,498
Defined
benefit pension plan and other post-retirement benefit plan deficits
24
i9,254
i8,592
i122,287
i120,891
Total
liabilities
i182,086
i194,486
Net
assets
i85,568
i100,708
Equity
bp
shareholders’ equity
32
i71,250
i98,412
Non-controlling
interests
32
i14,318
i2,296
Total
equity
32
i85,568
i100,708
Helge
Lund Chairman
Bernard Looney Chief executive officer
22 March 2021
158
bp Annual Report and Form 20-F 2020
Financial
statements
Group cash flow statement
For the year ended 31 December
$ million
Note
2020
2019
2018
Operating
activities
Profit (loss) before taxation
(i24,888)
i8,154
i16,723
Adjustments
to reconcile profit before taxation to net cash provided by operating activities
Exploration expenditure written off
8
i9,920
i631
i1,085
Depreciation,
depletion and amortization
5
i14,889
i17,780
i15,457
Impairment
and (gain) loss on sale of businesses and fixed assets
4
i11,507
i7,882
i404
Earnings
from joint ventures and associates
i403
(i3,257)
(i3,753)
Dividends
received from joint ventures and associates
i1,442
i1,962
i1,535
Interest
receivable
(i258)
(i441)
(i468)
Interest
received
i74
i416
i348
Finance
costs
7
i3,115
i3,489
i2,528
Interest
paid
(i2,728)
(i2,870)
(i1,928)
Net
finance expense relating to pensions and other post-retirement benefits
24
i33
i63
i127
Share-based
payments
i723
i730
i690
Net
operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans
24
(i282)
(i238)
(i386)
Net
charge for provisions, less payments
i735
(i176)
i986
(Increase)
decrease in inventories
i3,963
(i3,406)
i672
(Increase)
decrease in other current and non-current assets
i4,230
(i2,335)
(i2,858)
Increase
(decrease) in other current and non-current liabilities
(i8,278)
i2,823
(i2,577)
Income
taxes paid
(i2,438)
(i5,437)
(i5,712)
Net
cash provided by operating activities
i12,162
i25,770
i22,873
Investing
activities
Expenditure on property, plant and equipment, intangible and other assets
(i12,306)
(i15,418)
(i16,707)
Acquisitions,
net of cash acquired
3
(i44)
(i3,562)
(i6,986)
Investment
in joint ventures
(i567)
(i137)
(i382)
Investment
in associates
(i1,138)
(i304)
(i1,013)
Total
cash capital expenditure
(i14,055)
(i19,421)
(i25,088)
Proceeds
from disposals of fixed assets
4
i491
i500
i940
Proceeds
from disposals of businesses, net of cash disposed
4
i4,989
i1,701
i1,911
Proceeds
from loan repayments
i717
i246
i666
Net
cash used in investing activities
(i7,858)
(i16,974)
(i21,571)
Financing
activities
Repurchase of shares
(i776)
(i1,511)
(i355)
Lease
liability payments
(i2,442)
(i2,372)
(i35)
Proceeds
from long-term financing
i14,736
i8,597
i9,038
Repayments
of long-term financing
(i12,179)
(i7,118)
(i7,175)
Net
increase (decrease) in short-term debt
(i1,234)
i180
i1,317
Issue
of perpetual hybrid bonds
i11,861
i—
i—
Payments
on perpetual hybrid bonds
(i89)
i—
i—
Payments
relating to transactions involving non-controlling interests (other)
(i8)
i—
i—
Receipts
relating to transactions involving non-controlling interests (other)
i665
i566
i—
Dividends
paid
bp shareholders
10
(i6,340)
(i6,946)
(i6,699)
Non-controlling
interests
(i238)
(i213)
(i170)
Net
cash provided by (used in) financing activities
i3,956
(i8,817)
(i4,079)
Currency
translation differences relating to cash and cash equivalents
i379
i25
(i330)
Increase
(decrease) in cash and cash equivalents
i8,639
i4
(i3,107)
Cash
and cash equivalents at beginning of year
i22,472
i22,468
i25,575
Cash
and cash equivalents at end of year
i31,111
i22,472
i22,468
bp
Annual Report and Form 20-F 2020
159
Notes on financial statements
1.iSignificant
accounting policies, judgements, estimates and assumptions
i
Authorization of financial statements and statement of compliance with International Financial Reporting Standards
The consolidated financial statements of BP p.l.c and its subsidiaries (collectively referred to as bp or the group) for the year ended 31 December 2020 were approved and signed by the chief executive officer and chairman on 22 March 2021 having been duly authorized to do so by the board of directors.
BP p.l.c. is a public limited company incorporated and domiciled in England and Wales. The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB), IFRS adopted pursuant to Regulation (EC) No 1606/2002 as it applies in the European Union (EU) and in accordance with the provisions of the UK Companies Act 2006 as applicable to companies reporting under international accounting standards. IFRS as adopted by the EU differs in certain respects from IFRS as issued by the IASB. The differences have no impact on the group’s consolidated financial statements for the years presented. As a result of the UK's withdrawal from the EU, with effect for periods starting subsequent to the year ended 31 December 2020, the consolidated financial statements will also be prepared in accordance with UK-adopted international accounting standards. There were no
differences between IFRS as adopted by the EU and UK-adopted international accounting standards as at 1 January 2021. The UK’s withdrawal from the EU has not had and is not expected to have a significant impact on the consolidated financial statements. The significant accounting policies and accounting judgements, estimates and assumptions of the group are set out below.
Basis of preparation
The consolidated financial statements have been prepared on a going concern basis and in accordance with IFRS and IFRS Interpretations Committee (IFRIC) interpretations issued and effective for the year ended 31 December 2020. The accounting policies that follow have been consistently applied to all years presented, except where otherwise indicated.
The consolidated financial statements are presented in US dollars and all values are rounded to the
nearest million dollars ($ million), except where otherwise indicated.
i
Significant accounting policies: use of judgements, estimates and assumptions
Inherent in the application of many of the accounting policies used in preparing the consolidated financial statements is the need for bp management to make judgements, estimates and assumptions that affect the reported amounts of
assets and liabilities, the disclosure of contingent assets and liabilities, and the reported amounts of revenues and expenses. Actual outcomes could differ from the estimates and assumptions used. The accounting judgements and estimates that have a significant impact on the results of the group are set out in boxed text below, and should be read in conjunction with the information provided in the Notes on financial statements. The areas requiring the most significant judgement and estimation in the preparation of the consolidated financial statements are: accounting for the investment in Rosneft; exploration and appraisal intangible assets; the recoverability of asset carrying values, including the estimation of reserves; supplier financing arrangements; derivative financial instruments; provisions and contingencies; and pensions and other post-retirement benefits. Judgements and estimates, not all of which are significant, made in assessing the impact of the COVID-19
pandemic, and climate change and the transition to a lower carbon economy on the consolidated financial statements are also set out in boxed text below. Where an estimate has a significant risk of resulting in a material adjustment to the carrying amounts of assets and liabilities within the next financial year this is specifically noted within the boxed text.
Judgements and estimates made in assessing the impact of climate change and the transition to a lower carbon economy
Climate change and the transition to a lower carbon economy were considered in preparing the consolidated financial statements. These may have significant impacts on the currently reported amounts of the group’s assets and liabilities discussed below and on similar assets and liabilities
that may be recognized in the future.
Impairment of property, plant and equipment, and goodwill
The energy transition is likely to impact the future prices of commodities such as oil and natural gas which in turn may affect the recoverable amount of property, plant and equipment, and goodwill in the oil and gas industry. Management’s best estimate of oil and natural gas price assumptions for value-in-use impairment testing were revised downwards during 2020 and the period covered extended to 2050. The revised assumptions sit within the range of external forecasts considered by management and are broadly in line with a range of transition paths consistent with the goals of the Paris climate change agreement. See significant judgements and estimates: recoverability of asset carrying values for further information including sensitivity analysis in relation to reasonably possible changes in the
price assumptions.
Impairments were recognized during 2020 on certain Upstream oil and gas properties as a result of the lower price assumptions. See note 4 for further information.
No material impairments were recognized on Downstream assets. Though the energy transition may impact demand for certain refined products in the future, management anticipates sufficiently robust demand for the remainder of each refinery’s useful life.
Headroom on goodwill balances was reduced, however the recoverable amount exceeds the carrying amount. See note 14 for further information including sensitivity analysis on the assumptions used to test goodwill for impairment.
Management will continue to review price assumptions as the energy transition progresses and this may result in impairment charges or reversals
in the future.
Exploration and appraisal intangible assets
The energy transition may affect the future development or viability of exploration prospects. The lower price assumptions and work to develop bp’s new strategy resulted in a review of the recoverability of exploration and appraisal intangible assets during 2020. Certain intangible assets were subsequently written-off. See significant judgement: exploration and appraisal intangible assets and note 8 for further information.
The revised long-term price assumptions for investment appraisal (see page 28) help create a framework that seeks to help ensure that currently unsanctioned future capital expenditure on property plant and equipment, and exploration and appraisal intangibles, is aligned with bp’s new strategy.
Property, plant and equipment – depreciation
and expected useful lives
The energy transition may curtail the expected useful lives of oil and gas industry assets thereby accelerating depreciation charges. However, the significant majority of bp’s existing Upstream oil and natural gas properties are likely to be fully depreciated within the next 10 years and, as outlined in bp's new strategy, oil and natural gas production will remain an important part of bp’s business activities over that period. Similarly, for Downstream refineries, demand for refined products is expected to remain strong over the remaining useful life of existing assets.
160
bp
Annual Report and Form 20-F 2020
Financial statements
1.Significant accounting policies, judgements, estimates and assumptions– continued
Therefore, management does not expect the useful lives of bp’s reported property, plant and equipment to change and do not consider this to be a significant accounting judgement
or estimate. Significant capital expenditure is still required for ongoing projects and therefore the useful lives of future capital expenditure may, however, be different. See significant accounting policy: property, plant and equipment for more information.
Provisions: decommissioning
The energy transition may bring forward the decommissioning of oil and gas industry assets thereby increasing the present value of associated decommissioning provisions. The majority of bp’s Upstream oil and gas properties are expected to start decommissioning within the next two decades and management does not expect any reasonable change in the expected timeframe to have a material effect on the Upstream decommissioning provisions, assuming cash flows remain unchanged. Decommissioning cost estimates are based on the known regulatory and external environment. These cost estimates may
change in the future, including as a result of the transition to a lower carbon economy. For Downstream refineries, decommissioning provisions are generally not recognized as the associated obligations have indeterminate settlement dates, typically driven by the cessation of manufacturing. Management will continue to review facts and circumstances to assess if decommissioning provisions need to be recognized. See significant judgements and estimates: provisions for further information.
Judgements and estimates made in assessing the impact of the COVID-19 pandemic and the economic environment
In preparing the consolidated financial statements, the following
areas involving judgement and estimates were identified as most relevant with regards to the impact of the COVID-19 pandemic and current economic environment.
Going concern
Forecast liquidity has been assessed under a number of stressed scenarios, including a significant decline in oil prices over the 12-month period. Reverse stress tests performed indicated that the group will continue to operate as a going concern for at least 12 months from the date of approval of the consolidated financial statements even if the Brent price fell to zero. No material uncertainties over going concern or significant judgements or estimates in the assessment were identified. See also Note 29 Financial instruments and financial risk factors – Liquidity risk for further information.
Discount rate assumptions
The discount rates used
for impairment testing and provisions were reassessed during the year in light of changing economic and geopolitical outlooks. The impact was determined not to be significant and the post-tax impairment discount rate and nominal provisions discount rate were unchanged from 2019. Pre-tax impairment discount rates and post-tax premiums for certain higher-risk countries were changed but this did not have a material impact. See significant judgements and estimates: recoverability of asset carrying values and provisions for further information.
Oil and natural gas price assumptions
The price assumptions used in value-in-use impairment testing were revised downwards during the year, in part due to lower demand for oil and natural gas. Material impairment charges and exploration write-offs were recognized in the Upstream segment as a consequence of these price assumption changes. See significant
judgements and estimates: recoverability of asset carrying values and exploration and appraisal intangible assets for further information.
Demand constraints for refined products during the year did not result in any material impairment charges on Downstream refinery assets.
Pensions and other post-retirement benefits
The volatility in the financial markets during 2020 impacted the assumptions used for determining the fair value of plan assets and the present value of defined benefit obligations in the group’s defined benefit pension plans. See significant estimate: pensions and other post-retirement benefits and note 24 for further information.
Impairment of financial assets measured at amortized cost
The current economic environment and future credit risk outlook were
considered in updating the estimate of expected credit loss allowances on financial assets measured at amortized cost. Whilst credit risk increased relative to 31 December 2019, there was also a significant reduction in the group's trade and other receivables balance. Therefore, the total expected credit loss allowances recognized as at 31 December 2020 did not significantly increase. Management does not consider the calculation of expected credit loss allowances to be a significant accounting estimate. See note 21 and 29 for further information.
Income taxes
The carrying amounts of the group’s deferred tax assets were reviewed and updated to the extent that there are changes in the probability of sufficient taxable profits being available to utilize the reported deferred tax assets. Management does not consider the measurement of deferred tax assets to be a significant accounting estimate.
See significant accounting policy: income taxes and Note 9 for further information.
iBasis of consolidation
The consolidated group financial statements consolidate the financial statements of BP p.l.c. and its subsidiaries drawn up to 31 December each year. Subsidiaries
are consolidated from the date of their acquisition, being the date on which the group obtains control, including when control is obtained via potential voting rights, and continue to be consolidated until the date that control ceases. The financial statements of subsidiaries are prepared for the same reporting year as the parent company, using consistent accounting policies. Intra-group balances and transactions, including unrealized profits arising from intra-group transactions, have been eliminated. Unrealized losses are eliminated unless the transaction provides evidence of an impairment of the asset transferred. Non-controlling interests represent the equity in subsidiaries that is not attributable, directly or indirectly, to bp shareholders. Included within non-controlling interests
are perpetual subordinated hybrid bonds issued by a subsidiary and for which the group has the unconditional right to avoid transferring cash or another financial asset to the bondholders. Profit or loss attributable to bp shareholders is adjusted to reflect the coupon related to these hybrid bonds whether or not such distribution has been deferred.
i
Interests in other entities
Business combinations
and goodwill
Business combinations are accounted for using the acquisition method. The identifiable assets acquired and liabilities assumed are recognized at their fair values at the acquisition date.
Goodwill is initially measured as the excess of the aggregate of the consideration transferred, the amount recognized for any non-controlling interest and the acquisition-date fair values of any previously held interest in the acquiree over the fair value of the identifiable assets acquired and liabilities assumed at the acquisition date. The amount recognized for any non-controlling interest is measured at the present ownership's proportionate share in
bp
Annual Report and Form 20-F 2020
161
1.Significant accounting policies, judgements, estimates and assumptions– continued
the recognized amounts of the acquiree’s identifiable net assets. At the acquisition date, any goodwill acquired is allocated to each of the cash-generating units, or groups of cash-generating units, expected to benefit from the combination’s synergies. Following initial recognition, goodwill is measured at cost less any accumulated impairment losses. Goodwill arising on business combinations prior to 1 January 2003 is stated at the previous carrying amount under UK generally
accepted accounting practice, less subsequent impairments.
Goodwill may arise upon investments in joint ventures and associates, being the surplus of the cost of investment over the group’s share of the net fair value of the identifiable assets and liabilities. Any such goodwill is recorded within the corresponding investment in joint ventures and associates.
Goodwill may also arise upon acquisition of interests in joint operations that meet the definition of a business. The amount of goodwill separately recognized is the excess of the consideration transferred over the group's share of the net fair value of the identifiable assets and liabilities.
i
Interests
in joint arrangements
The results, assets and liabilities of joint ventures are incorporated in these consolidated financial statements using the equity method of accounting as described below.
Certain of the group’s activities, particularly in the Upstream segment, are conducted through joint operations. bp recognizes, on a line-by-line basis in the consolidated financial statements, its share of the assets, liabilities and expenses of these joint operations incurred jointly with the other partners, along with the group’s income from the sale of its share of the output and any liabilities and expenses that the group has incurred in relation to the joint operation.
Interests in associates
The results, assets and liabilities of associates are incorporated in these consolidated financial statements
using the equity method of accounting as described below.
Significant judgement: investment in Rosneft
Judgement is required in assessing the level of control or influence over another entity in which the group holds an interest. For bp, the judgement that the group has significant influence over Rosneft Oil Company (Rosneft), a Russian oil and gas company is significant. As a consequence of this judgement, bp uses the equity method of accounting for its investment and bp's share of Rosneft's oil and natural gas reserves is included in the group's estimated net proved reserves of equity-accounted entities. If significant influence was not present, the investment would be accounted for as an investment in an equity instrument measured at fair value as described
under 'Financial assets' below and no share of Rosneft's oil and natural gas reserves would be reported.
Significant influence is defined in IFRS as the power to participate in the financial and operating policy decisions of the investee but is not control or joint control of those policies. Significant influence is presumed when an entity owns 20% or more of the voting power of the investee. Significant influence is presumed not to be present when an entity owns less than 20% of the voting power of the investee.
bp owns i19.75%
of the voting shares of Rosneft. Rosneft’s largest shareholder is Rosneftegaz JSC (Rosneftegaz), which is wholly owned by the Russian government. At 31 December 2020, Rosneftegaz held i40.4% (2019 i50%
plus ione share) of the voting shares of Rosneft . IFRS identifies several indicators that may provide evidence of significant influence, including representation on the board of directors of the investee and participation in policy-making processes. bp’s group chief executive, Bernard Looney, was approved as a member of the board of directors of Rosneft in June 2020 as one of bp’s two nominated directors. bp’s other nominated director, Bob Dudley, has been a
member of the Rosneft board since 2013. He is also chairman of the Rosneft board’s Strategic and Sustainable Development Committee. bp also holds the voting rights at general meetings of shareholders conferred by its i19.75% stake in Rosneft. Transactions by Rosneft in its own shares during the year have increased bp’s economic interest in Rosneft to i22.03%
(2019 i19.75%). bp's management considers, therefore, that the group has significant influence over Rosneft, as defined by IFRS.
The equity method of accounting
Under the equity method, an investment is carried on the balance sheet at cost plus post-acquisition changes in the group’s share of net assets of the entity, less distributions received and less any impairment in value of the investment. Loans advanced to equity-accounted entities that have the characteristics
of equity financing are also included in the investment on the group balance sheet. The group income statement reflects the group’s share of the results after tax of the equity-accounted entity, adjusted to account for depreciation, amortization and any impairment of the equity-accounted entity’s assets based on their fair values at the date of acquisition. The group statement of comprehensive income includes the group’s share of the equity-accounted entity’s other comprehensive income. The group’s share of amounts recognized directly in equity by an equity-accounted entity is recognized in the group’s statement of changes in equity.
Financial statements of equity-accounted entities are prepared for the same reporting year as the group. Where material differences arise in the accounting policies used by the equity-accounted entity and those used by bp, adjustments are made to those financial statements to bring the accounting
policies used into line with those of the group.
Unrealized gains on transactions, apart from those that meet the definition of a derivative, between the group and its equity-accounted entities are eliminated to the extent of the group’s interest in the equity-accounted entity.
The group assesses investments in equity-accounted entities for impairment whenever there is objective evidence that the investment is impaired. If any such objective evidence of impairment exists, the carrying amount of the investment is compared with its recoverable amount, being the higher of its fair value less costs of disposal and value in use. If the carrying amount exceeds the recoverable amount, the investment is written down to its recoverable amount.
/i
Segmental
reporting
The group’s operating segments are established on the basis of those components of the group that are evaluated regularly by the group chief executive, bp’s chief operating decision maker, in deciding how to allocate resources and in assessing performance.
The accounting policies of the operating segments are the same as the group’s accounting policies described in this note, except that IFRS requires that the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision maker. For bp, this measure of profit or loss is replacement cost profit before interest and tax which reflects the replacement cost of inventories sold in the period and is arrived at by excluding inventory holding gains and losses from profit before interest and tax. Replacement cost profit for the group is not a recognized measure
under IFRS. For further information see Note 5.
For information on changes to bp's segmental reporting see ‘Change in segmentation from 1 January 2021’ below.
i
162
bp
Annual Report and Form 20-F 2020
Financial statements
1.Significant accounting policies, judgements, estimates and assumptions– continued
Foreign currency translation
In individual subsidiaries, joint ventures and associates, transactions in foreign currencies are initially recorded in the functional currency
of those entities at the spot exchange rate on the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated into the functional currency at the spot exchange rate on the balance sheet date. Any resulting exchange differences are included in the income statement, unless hedge accounting is applied. Non-monetary items, other than those measured at fair value, are not retranslated subsequent to initial recognition.
In the consolidated financial statements, the assets and liabilities of non-US dollar functional currency subsidiaries, joint ventures, associates, and related goodwill, are translated into US dollars at the spot exchange rate on the balance sheet date. The results and cash flows of non-US dollar functional currency subsidiaries,
joint ventures and associates are translated into US dollars using average rates of exchange. In the consolidated financial statements, exchange adjustments arising when the opening net assets and the profits for the year retained by non-US dollar functional currency subsidiaries, joint ventures and associates are translated into US dollars are recognized in a separate component of equity and reported in other comprehensive income. Exchange gains and losses arising on long-term intra-group foreign currency borrowings used to finance the group’s non-US dollar investments are also reported in other comprehensive income if the borrowings form part of the net investment in the subsidiary, joint venture or associate. On disposal or for certain partial disposals of a non-US dollar functional currency subsidiary, joint venture or associate, the related accumulated exchange gains and losses
recognized in equity are reclassified from equity to the income statement.
i
Non-current assets held for sale
Non-current assets and disposal groups classified as held for sale are measured at the lower of carrying amount and fair value less costs to sell.
Significant non-current assets and disposal groups are classified as held for sale if their carrying
amounts will be recovered through a sale transaction rather than through continuing use. This condition is regarded as met only when the sale is highly probable and the asset or disposal group is available for immediate sale in its present condition subject only to terms that are usual and customary for sales of such assets. Management must be committed to the sale, which should be expected to qualify for recognition as a completed sale within one year from the date of classification as held for sale, and actions required to complete the plan of sale should indicate that it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn.
Property, plant and equipment and intangible assets are not depreciated or amortized once classified as held for sale.
i
Intangible
assets
Intangible assets, other than goodwill, include expenditure on the exploration for and evaluation of oil and natural gas resources, computer software, patents, licences and trademarks and are stated at the amount initially recognized, less accumulated amortization and accumulated impairment losses.
Intangible assets are carried initially at cost unless acquired as part of a business combination. Any such asset is measured at fair value at the date of the business combination and is recognized separately from goodwill if the asset is separable or arises from contractual or other legal rights.
Intangible assets with a finite life, other than capitalized exploration and appraisal costs as described below, are amortized on a straight-line basis over their expected useful lives. For patents, licences and trademarks, expected useful life
is the shorter of the duration of the legal agreement and economic useful life, and can range from three to ififteen years. Computer software costs generally have a useful life of three to ifive
years.
The expected useful lives of assets and the amortization method are reviewed on an annual basis and, if necessary, changes in useful lives or the amortization method are accounted for prospectively.
Oil and natural gas exploration, appraisal and development expenditure
Oil and natural gas exploration, appraisal and development expenditure is accounted for using the principles of the successful efforts method of accounting as described below.
Licence and property acquisition costs
Exploration licence and leasehold property acquisition costs are capitalized within intangible assets and are reviewed at each reporting date to confirm that there is no indication that the carrying amount exceeds the recoverable amount. This review includes confirming
that exploration drilling is still under way or planned or that it has been determined, or work is under way to determine, that the discovery is economically viable based on a range of technical and commercial considerations, and sufficient progress is being made on establishing development plans and timing. If no future activity is planned, the remaining balance of the licence and property acquisition costs is written off. Lower value licences are pooled and amortized on a straight-line basis over the estimated period of exploration. Upon internal approval for development and recognition of proved or sanctioned probable reserves of oil and natural gas, the relevant expenditure is transferred to property, plant and equipment.
/i
Exploration
and appraisal expenditure
Geological and geophysical exploration costs are recognized as an expense as incurred. Costs directly associated with an exploration well are initially capitalized as an intangible asset until the drilling of the well is complete and the results have been evaluated. These costs include employee remuneration, materials and fuel used, rig costs and payments made to contractors. If potentially commercial quantities of hydrocarbons are not found, the exploration well costs are written off. If hydrocarbons are found and, subject to further appraisal activity, are likely to be capable of commercial development, the costs continue to be carried as an asset. If it is determined that development will not occur, that is, the efforts are not successful, then the costs are expensed.
Costs directly associated with appraisal activity undertaken to determine the size, characteristics
and commercial potential of a reservoir following the initial discovery of hydrocarbons, including the costs of appraisal wells where hydrocarbons were not found, are initially capitalized as an intangible asset. Upon internal approval for development and recognition of proved or sanctioned probable reserves, the relevant expenditure is transferred to property, plant and equipment. If development is not approved and no further activity is expected to occur, then the costs are expensed.
The determination of whether potentially economic oil and natural gas reserves have been discovered by an exploration well is usually made within one year of well completion, but can take longer, depending on the complexity of the geological structure. Exploration wells that discover potentially economic quantities of oil and natural gas and are in areas where major capital expenditure (e.g. an offshore platform or a pipeline) would be required
before production could begin, and where the economic viability of that major capital expenditure depends on the successful completion of further exploration or appraisal work in the area, remain capitalized on the balance sheet as long as such work is under way or firmly planned.
bp Annual Report and Form 20-F 2020
163
1.Significant accounting policies, judgements, estimates and assumptions– continued
Development expenditure
Expenditure on the construction, installation and completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells, including service and unsuccessful development or delineation wells, is capitalized within property, plant and equipment and is depreciated from the commencement of production as described below in the accounting policy for property, plant and equipment.
Significant judgement: exploration and appraisal intangible assets
Judgement is
required to determine whether it is appropriate to continue to carry costs associated with exploration wells and exploratory-type stratigraphic test wells on the balance sheet. This includes costs relating to exploration licences or leasehold property acquisitions. It is not unusual to have such costs remaining suspended on the balance sheet for several years while additional appraisal drilling and seismic work on the potential oil and natural gas field is performed or while the optimum development plans and timing are established.The costs are carried based on the current regulatory and political environment or any known changes to that environment. All such carried costs are subject to regular technical, commercial and management review on at least an annual basis to confirm the continued intent to develop, or otherwise extract value from, the discovery. Where this is no longer the case, the costs are immediately expensed.
As
a result of the revised price assumptions detailed in Significant judgements and estimates: recoverability of asset carrying values below and a review of bp’s long-term strategic plan, management reviewed bp’s exploration prospects and the carrying value of the associated intangible assets. The outcome of the review resulted in revised judgements over management's expectations to extract value from certain prospects, thereby leading to material write-offs of the associated exploration and appraisal intangible assets in 2020.
The carrying amount of capitalized costs and further information on the write-offs are included in Note 8.
i
Property,
plant and equipment
Property, plant and equipment owned by the group is stated at cost, less accumulated depreciation and accumulated impairment losses. The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into the location and condition necessary for it to be capable of operating in the manner intended by management, the initial estimate of any decommissioning obligation, if applicable, and, for assets that necessarily take a substantial period of time to get ready for their intended use, directly attributable general or specific finance costs. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset.
Expenditure on major maintenance refits or repairs comprises the cost of replacement assets or parts of assets, inspection
costs and overhaul costs. Where an asset or part of an asset that was separately depreciated is replaced and it is probable that future economic benefits associated with the item will flow to the group, the expenditure is capitalized and the carrying amount of the replaced asset is derecognized. Inspection costs associated with major maintenance programmes are capitalized and amortized over the period to the next inspection. Overhaul costs for major maintenance programmes, and all other maintenance costs are expensed as incurred.
Oil and natural gas properties, including certain related pipelines, are depreciated using a unit-of-production method. The cost of producing wells is amortized over proved developed reserves. Licence acquisition, common facilities and future decommissioning costs are amortized over total proved reserves. The unit-of-production rate for the depreciation of common facilities takes into account expenditures
incurred to date, together with estimated future capital expenditure expected to be incurred relating to as yet undeveloped reserves expected to be processed through these common facilities. Information on the carrying amounts of the group’s oil and natural gas properties, together with the amounts recognized in the income statement as depreciation, depletion and amortization is contained in Note 12 and Note 5 respectively.
Estimates of oil and natural gas reserves determined in accordance with US Securities and Exchange Commission (SEC) regulations, including the application of prices using 12-month historical price data in assessing the commerciality of technical volumes, are typically used to calculate depreciation, depletion and amortization charges for the group’s oil and gas properties. Therefore, where this approach is adopted, charges are not dependent on management forecasts of future oil and gas prices.
However,
for certain oil and natural gas assets, the use of reserves determined in accordance with SEC regulations would result in a charge that is not reflective of the pattern in which the future economic benefits are expected to be consumed. In these limited instances other approaches are applied to determine the reserves base used to calculate depreciation, depletion and amortization, including the use of management’s best estimate of price assumptions as disclosed in Significant judgements and estimates: recoverability of asset carrying values, to determine the commerciality of technical proved reserves.
The impact of changes in estimated proved reserves is dealt with prospectively by amortizing the remaining carrying value of the asset over the expected future production.
The estimation of oil and natural gas reserves and bp’s process to manage reserves bookings is described in Supplementary
information on oil and natural gas on page 231, which is unaudited. Details on bp’s proved reserves and production compliance and governance processes are provided on page 312. The 2020 movements in proved reserves are reflected in the tables showing movements in oil and natural gas reserves by region in Supplementary information on oil and natural gas (unaudited) on page 231.
i
Other property, plant and equipment is depreciated on a straight-line
basis over its expected useful life. The typical useful lives of the group’s other property, plant and equipment are as follows:
Land improvements
i15 to i25 years
Buildings
i20 to i50 years
Refineries
i20 to i30
years
Petrochemicals plants
i20 to i30 years
Pipelines
i10
to i50 years
Service stations
i15 years
Office
equipment
i3 to i10 years
Fixtures and fittings
i5
to i15 years
/
The expected useful lives and depreciation method of property, plant and equipment are reviewed on an annual basis and, if necessary, changes in useful lives or the depreciation method are accounted for prospectively.An item of property, plant and equipment is derecognized upon disposal or when no future economic benefits are expected to arise from the continued
use of the asset. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the item) is included in the income statement in the period in which the item is derecognized.
/
164
bp Annual Report and Form 20-F 2020
Financial
statements
1.Significant accounting policies, judgements, estimates and assumptions– continued
i
Impairment of property, plant and equipment, intangible assets, and goodwill
The group assesses assets or groups of assets, called cash-generating units (CGUs), for
impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or CGU may not be recoverable; for example, changes in the group’s business plans, plans to dispose rather than retain assets, changes in the group’s assumptions about commodity prices, low plant utilization, evidence of physical damage or, for oil and gas assets, significant downward revisions of estimated reserves or increases in estimated future development expenditure or decommissioning costs. If any such indication of impairment exists, the group makes an estimate of the asset’s or CGU’s recoverable amount. Individual assets are grouped into CGUs for impairment assessment purposes at the lowest level at which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. A CGU’s recoverable amount is the higher of its fair value less costs of disposal and its value in use. If it is probable that the value of the CGU will
be primarily recovered through a disposal transaction, the expected disposal proceeds are considered in determining the recoverable amount. Where the carrying amount of a CGU exceeds its recoverable amount, the CGU is considered impaired and is written down to its recoverable amount.
The business segment plans, which are approved on an annual basis by senior management, are the primary source of information for the determination of value in use. They contain forecasts for oil and natural gas production, refinery throughputs, sales volumes for various types of refined products (e.g. gasoline and lubricants), revenues, costs and capital expenditure. Carbon taxes and costs of emissions allowances are included in estimates of future cash flows, where applicable, based on the regulatory environment in each jurisdiction in which the group operates. As an initial step in the preparation of these plans, various assumptions regarding
market conditions, such as oil prices, natural gas prices, refining margins, refined product margins and cost inflation rates are set by senior management. These assumptions take account of existing prices, global supply-demand equilibrium for oil and natural gas, other macroeconomic factors and historical trends and variability. In assessing value in use, the estimated future cash flows are adjusted for the risks specific to the asset group that are not reflected in the discount rate and are discounted to their present value typically using a pre-tax discount rate that reflects current market assessments of the time value of money.
Fair value less costs of disposal is the price that would be received to sell the asset in an orderly transaction between market participants and does not reflect the effects of factors that may be specific to the group and not applicable to entities in general. In limited circumstances where recent
market transactions are not available for reference, discounted cash flow techniques are applied. Where discounted cash flow analyses are used to calculate fair value less costs of disposal, estimates are made about the assumptions market participants would use when pricing the asset, CGU or group of CGUs containing goodwill and the test is performed on a post-tax basis.
An assessment is made at each reporting date as to whether there is any indication that previously recognized impairment losses may no longer exist or may have decreased. If such an indication exists, the recoverable amount is estimated. A previously recognized impairment loss is reversed only if there has been a change in the estimates used to determine the asset’s recoverable amount since the last impairment loss was recognized. If that is the case, the carrying amount of the asset is increased to the lower of its recoverable amount and the carrying amount
that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years. Impairment reversals are recognized in profit or loss. After a reversal, the depreciation charge is adjusted in future periods to allocate the asset’s revised carrying amount, less any residual value, on a systematic basis over its remaining useful life.
Goodwill is reviewed for impairment annually or more frequently if events or changes in circumstances indicate the recoverable amount of the group of CGUs to which the goodwill relates should be assessed. In assessing whether goodwill has been impaired, the carrying amount of the group of CGUs to which goodwill has been allocated is compared with its recoverable amount. Where the recoverable amount of the group of CGUs is less than the carrying amount (including goodwill), an impairment loss is recognized. An impairment loss recognized for goodwill is not
reversed in a subsequent period.
bp Annual Report and Form 20-F 2020
165
1.Significant accounting policies, judgements, estimates and assumptions– continued
Significant
judgements and estimates: recoverability of asset carrying values
Determination as to whether, and by how much, an asset, CGU, or group of CGUs containing goodwill is impaired involves management estimates on highly uncertain matters such as the effects of inflation and deflation on operating expenses, discount rates, capital expenditure, production profiles, reserves and resources, and future commodity prices, including the outlook for global or regional market supply-and-demand conditions for crude oil, natural gas and refined products. Judgement is required when determining the appropriate grouping of assets into a CGU or the appropriate grouping of CGUs for impairment testing purposes. For example, individual oil and gas properties may form separate CGUs whilst certain oil and gas properties with shared infrastructure may be grouped together to form a single CGU. Alternative groupings of assets or CGUs may result in a
different outcome from impairment testing. See Note 14 for details on how these groupings have been determined in relation to the impairment testing of goodwill.
As described above, the recoverable amount of an asset is the higher of its value in use and its fair value less costs of disposal. Fair value less costs of disposal may be determined based on expected sales proceeds or similar recent market transaction data.
Details of impairment charges and reversals recognized in the income statement are provided in Note 4 and details on the carrying amounts of assets are shown in Note 12, Note 14 and Note 15.
The estimates for assumptions made in impairment tests in 2020 relating to discount rates and oil and gas properties are discussed below. Changes in the economic environment or other facts and circumstances may necessitate revisions
to these assumptions and could result in a material change to the carrying values of the group's assets within the next financial year.
Discount rates
For discounted cash flow calculations, future cash flows are adjusted for risks specific to the CGU. Value-in-use calculations are typically discounted using a pre-tax discount rate based upon the cost of funding the group derived from an established model, adjusted to a pre-tax basis and incorporating a market participant capital structure and country risk premiums. Fair value less costs of disposal discounted cash flow calculations use the post-tax discount rate.
The discount rates applied in impairment tests are reassessed each year and in 2020, the post-tax discount rate was i6%
(2019 i6%). Where the CGU is located in a country that was judged to be higher risk an additional premium of i1%
to i3% was reflected in the post-tax discount rate (2019 i1%
to i4%). The judgement of classifying a country as higher risk and the applicable premium takes into account various economic and geopolitical factors. The pre-tax discount rate typically ranged from i7%
to i15% (2019 i7%
to i13%) depending on the risk premium and applicable tax rate in the geographic location of the CGU.
Oil and natural gas properties
For Upstream oil and natural gas properties, expected future cash flows are estimated using management’s best estimate of future oil and natural gas prices, and production and reserves volumes. The estimated future level of production in all impairment tests
is based on assumptions about future commodity prices, production and development costs, field decline rates, current fiscal regimes and other factors.
In 2020, the group identified Upstream oil and gas properties with carrying amounts totalling $i45,027 million (2019 $i25,092 million)
where the headroom, based on the most recent impairment test performed in the year on those assets, was less than or equal to i20% of the carrying value. A change in the discount rate, reserves, resources or the oil and gas price assumptions in the next financial year may result in a recoverable amount of one or more of these assets above or below the current carrying amount and therefore there is a risk of impairment reversals or charges in that period. Management
considers that reasonably possible changes in the discount rate or forecast revenue, arising from a change in oil and natural gas prices and/or production could result in a material change in their carrying amounts within the next financial year,see Sensitivity analyses, below.
The recoverability of intangible exploration and appraisal expenditure is covered under Oil and natural gas exploration, appraisal and development expenditure above.
Oil and natural gas prices
The price assumptions used for value in use impairment testing are based on those used for investment appraisal. The investment appraisalprice assumptions are recommended by the senior vice president economic & energy insights after considering a range of external prices, and supply and demand forecasts under various energy transition
scenarios. They are reviewed and approved by management. As a result of the current uncertainty over the pace of transition to lower-carbon supply and demand and the social, political and environmental actions that will be taken to meet the goals of the Paris climate change agreement, the forecasts and scenarios considered include those where those goals are met as well as those where they are not met.
bp sees the prospect of an enduring impact on the global economy as a result of the COVID-19 pandemic, with the potential for weaker demand for energy for a sustained period. bp’s management also expects that the aftermath of the pandemic will accelerate the pace of transition to a lower carbon economy and energy system as countries seek to ‘build back better’ so that their economies will be more resilient in the future. As a result of all the above, bp revised its price assumptions for value-in-use impairment testing, lowering
them compared to those used in 2019 and extending the period covered to 2050. These price assumptions are derived from the central case investment appraisal assumptions (see page 28). A summary of the group’s revised price assumptions, in real 2020 terms, is provided below. The assumptions represent management’s best estimate of future prices, which sit within the range of external forecasts considered as appropriate for the purpose. They are considered by bp to be broadly in line with a range of transition paths consistent with the Paris climate goals. However, they do not correspond to any specific Paris-consistent scenario. An inflation rate of i2%
(2019 i2%) is applied to determine the price assumptions in nominal terms.
2021
2025
2030
2040
2050
Brent
oil ($/bbl)
i50
i50
i60
i60
i50
Henry
Hub gas ($/mmBtu)
i3.00
i3.00
i3.00
i3.00
i2.75
166
bp
Annual Report and Form 20-F 2020
Financial statements
1.Significant accounting policies, judgements, estimates and assumptions– continued
Material impairment charges were recognized in 2020 following the downward revision of the price assumptions. See Note 4 for further information.
The
long-term price assumptions used to determine recoverable amount based on value-in-use impairments tests in 2019 were $i70 per barrel for Brent and $i4
per mmBtu for Henry Hub gas, both in 2015 prices. These long-term prices were applied from 2025 and 2032 respectively inflated for the remaining life of the asset.
The price assumptions used in 2019 over the periods to 2025 and 2032 were set such that there was a linear progression from our best estimate of 2020 prices to the long-term assumptions.
The majority of bp’s reserves and resources that support the carrying value of the group’s existing oil and gas properties are expected to be produced over the next 10 years.
Oil prices fell 35% in 2020 from 2019 due to trade tensions, a macroeconomic downturn and a slowdown in oil demand, reflecting the impact of the COVID-19 pandemic. OPEC+ production restraint, unplanned outages, and sanctions on Venezuela and Iran kept prices from falling further. bp's long-term assumption for oil prices
is higher than the 2020 price average, based on the judgement that current price levels would not encourage sufficient investment to meet global oil demand sustainably in the longer term, especially given the financial requirements of key low-cost oil producing economies.
US gas prices dropped by around 20% in 2020 compared to 2019. Henry Hub gas prices were already low in early 2020 due to mild weather. The drop in demand from the second quarter onward as a result of the COVID-19 pandemic as well as significant US LNG shut-ins contributed to prices remaining below $2/mmBtu during the second and third quarters, despite a record consumption in the power sector and the drop in natural gas production. Prices recovered in the fourth quarter due to the seasonal gas demand increase and the strong recovery in US LNG exports. bp's long-term price assumption for US gas reflects the fact that over the coming decades US gas production
increases with an increasing proportion of production being used as feedstock to supply expanding LNG exports, while in the longer-term falling gas consumption and declining demand for global LNG exports leads to increasing competitive pressure on US gas production.
Oil and natural gas reserves
In addition to oil and natural gas prices, significant technical and commercial assessments are required to determine the group’s estimated oil and natural gas reserves. Reserves estimates are regularly reviewed and updated. Factors such as the availability of geological and engineering data, reservoir performance data, acquisition and divestment activity and drilling of new wells all impact on the determination of the group’s estimates of its oil and natural gas reserves. bp bases its reserves estimates on the requirement of reasonable certainty with rigorous technical and commercial assessments based
on conventional industry practice and regulatory requirements.
Reserves assumptions for value-in-use tests reflect the reserves and resources that management currently intend to develop. The recoverable amount of oil and gas properties is determined using a combination of inputs including reserves, resources and production volumes. Risk factors may be applied to reserves and resources which do not meet the criteria to be treated as proved or probable.
Sensitivity analyses
A change in revenue from Upstream oil and gas properties can arise either due to changes in oil and natural gas prices, changes in oil and natural gas production, or a combination of the two.
Management tested the impact of a change in revenue cash flows in value-in-use impairment testing arising from changes in price assumptions and/or
production volumes up to a combined effect on revenue of 10% in all future years.
Revenue reductions of this magnitude in isolation could indicatively lead to a reduction in the carrying amount of bp’s Upstream oil and gas properties in the range of $i6-i7
billion, which is approximately i5-i6%
of the net book value of property, plant and equipment as at 31 December 2020.
Revenue increases of this magnitude in isolation could indicatively lead to an increase in the carrying amount of bp’s Upstream oil and gas properties in the range of $i4-i5
billion, which is approximately i3-i4%
of the net book value of property, plant and equipment as at 31 December 2020. This potential increase in the carrying amount would arise due to reversals of previously recognized impairments.
These sensitivity analyses do not, however, represent management’s best estimate of any impairment charges or reversals that might be recognized as they do not fully incorporate consequential changes that may arise, such as changes in costs and business plans and phasing of development. For example, costs across the industry are more likely to decrease as oil and natural gas prices fall. The above sensitivity analyses therefore do not reflect a linear relationship between revenue and value that can be extrapolated. The interdependency of these inputs and risk factors plus the diverse characteristics of our Upstream oil and gas properties limits the practicability of estimating the probability or extent to which the overall recoverable
amount is impacted by changes to the price assumptions or production volumes.
Management also tested the impact of a one percentage point change in the discount rate used for value-in-use impairment testing of Upstream oil and gas properties. If the discount rate was one percentage point higher across all tests performed, the impairment charge recognized in 2020 would have been approximately $i2.4 billion
higher. If the discount rate was one percentage point lower, the impairment charge recognized would have been approximately $i2.7 billion lower.
Goodwill
Irrespective of whether there is any indication of impairment, bp is required to test annually for impairment of goodwill acquired in business
combinations. The group carries goodwill of approximately $i12.5 billion on its balance sheet (2019 $i11.9 billion), principally relating to the Atlantic Richfield,
Burmah Castrol, Devon Energy and Reliance transactions. Sensitivities and additional information relating to impairment testing of goodwill in the Upstream segment are provided in Note 14.
i
Inventories
Inventories, other than inventories held for short-term trading purposes, are stated at the lower of cost and net realizable value. Cost is determined by the first-in first-out method and comprises direct purchase costs, cost of production, transportation and manufacturing expenses.
Net realizable value is determined by reference to prices existing at the balance sheet date, adjusted where the sale of inventories after the reporting period gives evidence about their net realizable value at the end of the period.
Inventories held for short-term trading purposes are stated at fair value less costs to sell and any changes in fair value are recognized in the income statement.
Supplies are valued at the lower of cost on a weighted average basis and net realizable value.
bp
Annual Report and Form 20-F 2020
167
1.Significant accounting policies, judgements, estimates and assumptions– continued
i
Leases
Agreements that convey the right to control
the use of an identified asset for a period of time in exchange for consideration are accounted for as leases. The right to control is conveyed if bp has both the right to obtain substantially all of the economic benefits from, and the right to direct the use of, the identified asset throughout the period of use. An asset is identified if it is explicitly or implicitly specified by the agreement and any substitution rights held by the lessor over the asset are not considered substantive.
Agreements that convey the right to control the use of an intangible asset including rights to explore for or use hydrocarbons are not accounted for as leases. See significant accounting policy: intangible assets.
A lease liability is recognized on the balance sheet on the lease commencement date at the present value of future lease payments over the lease term. The discount rate applied is the rate
implicit in the lease if readily determinable, otherwise an incremental borrowing rate is used. The incremental borrowing rate is determined based on factors such as the group’s cost of borrowing, lessee legal entity credit risk, currency and lease term. The lease term is the non-cancellable period of a lease together with any periods covered by an extension option that bp is reasonably certain to exercise, or periods covered by a termination option that bp is reasonably certain not to exercise. The future lease payments included in the present value calculation are any fixed payments, payments that vary depending on an index or rate, payments due for the reasonably certain exercise of options and expected residual value guarantee payments. Repayments of principal are presented as financing cash flows and payments of interest are presented as operating cash flows.
Payments that vary based on factors other than an index or a
rate such as usage, sales volumes or revenues are not included in the present value calculation and are recognized in the income statement and presented as operating cash flows. The lease liability is recognized on an amortized cost basis with interest expense recognized in the income statement over the lease term, except for where capitalized as exploration, appraisal or development expenditure.
The right-of-use asset is recognized on the balance sheet as property, plant and equipment at a value equivalent to the initial measurement of the lease liability adjusted for lease prepayments, lease incentives, initial direct costs and any restoration obligations. The right-of-use asset is depreciated typically on a straight-line basis over the lease term. The depreciation charge is recognized in the income statement except for where capitalized as exploration, appraisal or development expenditure. Right-of-use assets are assessed
for impairment in line with the accounting policy for impairment of property, plant and equipment, intangible assets and goodwill.
Agreements may include both lease and non-lease components. Payments for lease and non-lease components are allocated on a relative stand-alone selling price basis except for leases of retail service stations where the group has elected not to separate non-lease payments from the calculation of the lease liability and right-of-use asset.
If the lease term at commencement of the agreement is less than 12 months, a lease liability and right-of-use asset are not recognized, and a lease expense is recognized in the income statement on a straight-line basis.
If a significant event or change in circumstances, within the control of bp, arises that affects the reasonably certain lease term or there are changes to the
lease payments, the present value of the lease liability is remeasured using the revised term and payments, with the right-of-use asset adjusted by an equivalent amount.
Modifications to a lease agreement beyond the original terms and conditions are accounted for as a re-measurement of the lease liability with a corresponding adjustment to the right-of-use asset. Any gain or loss on modification is recognized in the income statement. Modifications that increase the scope of the lease at a price commensurate with the stand-alone selling price are accounted for as a separate new lease.
The group recognizes the full lease liability, rather than its working interest share, for leases entered into on behalf of a joint operation if the group has the primary responsibility for making the lease payments. This may be the case if for example bp, as operator of the joint operation, is the sole
signatory to the lease. In such cases, bp’s working interest share of the right-of-use asset is recognized if it is jointly controlled by the group and the other joint operators, and a receivable is recognized for the share of the asset transferred to the other joint operators. If bp is a non-operator, a payable to the operator is recognized if they have the primary responsibility for making the lease payments and bp has joint control over the right-of-use asset, otherwise no balances are recognized.
i
Financial
assets
Financial assets are recognized initially at fair value, normally being the transaction price. In the case of financial assets not measured at fair value through profit or loss, directly attributable transaction costs are also included. The subsequent measurement of financial assets depends on their classification, as set out below. The group derecognizes financial assets when the contractual rights to the cash flows expire or the rights to receive cash flows have been transferred to a third party and either substantially all of the risks and rewards of the asset have been transferred, or substantially all the risks and rewards of the asset have neither been retained nor transferred but control of the asset has been transferred. This includes the derecognition of receivables for which discounting arrangements are entered into.
The group classifies its financial asset debt instruments
as measured at amortized cost, fair value through other comprehensive income or fair value through profit or loss. The classification depends on the business model for managing the financial assets and the contractual cash flow characteristics of the financial asset.
Financial assets measured at amortized cost
Financial assets are classified as measured at amortized cost when they are held in a business model the objective of which is to collect contractual cash flows and the contractual cash flows represent solely payments of principal and interest. Such assets are carried at amortized cost using the effective interest method if the time value of money is significant. Gains and losses are recognized in profit or loss when the assets are derecognized or impaired and when interest is recognized using the effective interest method. This category of financial assets includes trade and
other receivables.
Financial assets measured at fair value through other comprehensive income
Financial assets are classified as measured at fair value through other comprehensive income when they are held in a business model the objective of which is both to collect contractual cash flows and sell the financial assets, and the contractual cash flows represent solely payments of principal and interest.
Financial assets measured at fair value through profit or loss
Financial assets are classified as measured at fair value through profit or loss when the asset does not meet the criteria to be measured at amortized cost or fair value through other comprehensive income. Such assets are carried on the balance sheet at fair value with gains or losses recognized in the income statement. Derivatives,
other than those designated as effective hedging instruments, are included in this category.
168
bp Annual Report and Form 20-F 2020
Financial
statements
1.Significant accounting policies, judgements, estimates and assumptions– continued
Investments in equity instruments
Investments in equity instruments are subsequently measured at fair value through profit or loss unless an election is made on an instrument-by-instrument basis to recognise fair value gains and losses in other comprehensive income.
Derivatives designated as hedging instruments in an effective hedge
Derivatives designated as hedging instruments in an effective hedge are carried on the balance sheet at fair value. The treatment of gains and losses arising from revaluation is described below in the accounting
policy for derivative financial instruments and hedging activities.
Cash equivalents
Cash equivalents are short-term highly liquid investments that are readily convertible to known amounts of cash, are subject to insignificant risk of changes in value and generally have a maturity of three months or less from the date of acquisition. Cash equivalents are classified as financial assets measured at amortized cost or, in the case of certain money market funds, fair value through profit or loss.
Impairment of financial assets measured at amortized cost
The group assesses on a forward-looking basis the expected credit losses associated with financial assets classified as measured at amortized cost at each balance sheet date. Expected credit losses are measured based on the maximum contractual period
over which the group is exposed to credit risk. As lifetime expected credit losses are recognized for trade receivables and the tenor of substantially all other in-scope financial assets is less than 12 months there is no significant difference between the measurement of 12-month and lifetime expected credit losses for the group. The measurement of expected credit losses is a function of the probability of default, loss given default and exposure at default. The expected credit loss is estimated as the difference between the asset’s carrying amount and the present value of the future cash flows the group expects to receive discounted at the financial asset’s original effective interest rate. The carrying amount of the asset is adjusted, with the amount of the impairment gain or loss recognized in the income statement.
A financial asset or group of financial assets classified as measured at amortized cost is considered to be
credit-impaired if there is reasonable and supportable evidence that one or more events that have a detrimental impact on the estimated future cash flows of the financial asset (or group of financial assets) have occurred. Financial assets are written off where the group has no reasonable expectation of recovering amounts due.
Equity instruments
Instruments are classified as either financial liabilities or as equity in accordance with the substance of the contractual arrangements. Instruments that cannot be settled in the group’s own equity instruments and that include no contractual obligation to deliver cash or another financial asset or to exchange financial assets or financial liabilities with another entity that are potentially unfavourable are classified as equity. Equity instruments issued by the group are recognized at the proceeds received, net of direct issue costs.
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Financial
liabilities
Financial liabilities are recognized when the group becomes party to the contractual provisions of the instrument. The group derecognizes financial liabilities when the obligation specified in the contract is discharged, cancelled or expired. The measurement of financial liabilities depends on their classification, as follows:
Financial liabilities measured at fair value through profit or loss
Financial liabilities that meet the definition of held for trading are classified as measured at fair value through profit or loss. Such liabilities are carried on the balance sheet at fair value with gains or losses recognized in the income statement. Derivatives, other than those designated as effective hedging instruments, are included in this
category.
Derivatives designated as hedging instruments in an effective hedge
Derivatives designated as hedging instruments in an effective hedge are carried on the balance sheet at fair value. The treatment of gains and losses arising from revaluation is described below in the accounting policy for derivative financial instruments and hedging activities.
Financial liabilities measured at amortized cost
All other financial liabilities are initially recognized at fair value, net of directly attributable transaction costs. For interest-bearing loans and borrowings this is typically equivalent to the fair value of the proceeds received, net of issue costs associated with the borrowing.
After initial recognition, other financial liabilities are subsequently
measured at amortized cost using the effective interest method. Amortized cost is calculated by taking into account any issue costs and any discount or premium on settlement. Gains and losses arising on the repurchase, settlement or cancellation of liabilities are recognized in interest and other income and finance costs respectively.
This category of financial liabilities includes trade and other payables and finance debt.
The group’s trade payables include some supplier arrangements that utilize letter of credit facilities. Judgement is required to assesses the payables subject to these arrangements to determine whether they should continue to be classified
as trade payables and give rise to operating cash flows or finance debt and financing cash flows. The criteria used in making this assessment include the payment terms for the amount due relative to terms commonly seen in the markets in which bp operates and whether the arrangements significantly change the nature of the liability. Liabilities subject to these arrangements with payment terms of up to approximately 60 days are generally considered to be trade payables and give rise to operating cash flows. See Note 29 - Liquidity risk for further information.
Financial guarantees
The group issues financial guarantee contracts to make specified payments to reimburse holders for losses incurred because certain associates, joint ventures or third-party entities fail to
make payments when due in accordance with the original or modified terms of a debt instrument such as a loan. The liability for a financial guarantee contract is initially measured at fair value and subsequently measured at the higher of the contract’s estimated expected credit loss and the amount initially recognized less, where appropriate, cumulative amortization.
Derivative financial instruments and hedging activities
The group uses derivative financial instruments to manage certain exposures to fluctuations in foreign currency exchange rates, interest rates and commodity prices, as well as for trading purposes. These derivative financial instruments are recognized initially at fair value on the
date on which a derivative contract is entered into and subsequently remeasured at fair value. Derivatives are carried as assets when the fair value is positive and as liabilities when the fair value is negative.
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1.Significant accounting policies, judgements, estimates and assumptions– continued
Contracts to buy or sell a non-financial item (for example, oil, oil products, gas or power) that can be settled net in cash, with the exception of contracts that were entered into and continue to be held for the purpose of the receipt or delivery of a non-financial item in accordance with the group’s expected purchase, sale or usage requirements, are accounted for as financial instruments. Gains or losses arising from changes in the fair value of derivatives that are not designated as effective hedging instruments are recognized in the income statement.
If,
at inception of a contract, the valuation cannot be supported by observable market data, any gain or loss determined by the valuation methodology is not recognized in the income statement but is deferred on the balance sheet and is commonly known as a ‘day-one gain or loss’. This deferred gain or loss is recognized in the income statement over the life of the contract until substantially all the remaining contract term can be valued using observable market data at which point any remaining deferred gain or loss is recognized in the income statement. Changes in valuation subsequent to the initial valuation at inception of a contract
are recognized immediately in the income statement.
For the purpose of hedge accounting, hedges are classified as:
•Fair value hedges when hedging exposure to changes in the fair value of a recognized asset or liability.
•Cash flow hedges when hedging exposure to variability in cash flows that is attributable to either a particular risk associated with a recognized asset or liability or a highly probable forecast transaction.
Hedge relationships are formally designated and documented at inception, together with the risk management objective and strategy for undertaking the hedge. The documentation includes identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, the existence at inception of an
economic relationship and subsequent measurement of the hedging instrument's effectiveness in offsetting the exposure to changes in the hedged item’s fair value or cash flows attributable to the hedged risk, the hedge ratio and sources of hedge ineffectiveness. Hedges meeting the criteria for hedge accounting are accounted for as follows:
Fair value hedges
The change in fair value of a hedging derivative is recognized in profit or loss. The change in the fair value of the hedged item attributable to the risk being hedged is recorded as part of the carrying value of the hedged item and is also recognized in profit or loss, where it offsets. The group applies fair value hedge accounting when hedging interest rate risk and certain currency risks on fixed rate finance debt.
Fair value hedge accounting is discontinued only when the hedging relationship
or a part thereof ceases to meet the qualifying criteria. This includes when the risk management objective changes or when the hedging instrument is sold, terminated or exercised. The accumulated adjustment to the carrying amount of a hedged item at such time is then amortized prospectively to profit or loss as finance interest expense over the hedged item's remaining period to maturity.
Cash flow hedges
The effective portion of the gain or loss on a cash flow hedging instrument is reported in other comprehensive income, while the ineffective portion is recognized in profit or loss. Amounts reported in other comprehensive income are reclassified to the income statement when the hedged transaction affects profit or loss.
Where the hedged item is a highly probably forecast transaction that results in the recognition of a non-financial asset
or liability, such as a forecast foreign currency transaction for the purchase of property, plant and equipment, the amounts recognized within other comprehensive income are transferred to the initial carrying amount of the non-financial asset or liability. Where the hedged item is an equity investment, the amounts recognized in other comprehensive income remain in the separate component of equity until the hedged cash flows affect profit or loss. Where the hedged item is recognized directly in profit or loss, the amounts recognized in other comprehensive income are reclassified to production and manufacturing expenses or sales and other operating revenues as appropriate.
Cash flow hedge accounting is discontinued only when the hedging relationship or a part thereof ceases to meet the qualifying criteria. This includes when the designated hedged forecast transaction or part thereof is no longer considered to be highly probable
to occur, or when the hedging instrument is sold, terminated or exercised without replacement or rollover. When cash flow hedge accounting is discontinued amounts previously recognized within other comprehensive income remain in equity until the forecast transaction occurs and are reclassified to profit or loss or transferred to the initial carrying amount of a non-financial asset or liability as above. If the forecast transaction is no longer expected to occur, amounts previously recognized within other comprehensive income will be immediately reclassified to profit or loss.
Costs of hedging
The foreign currency basis spread of cross-currency interest rate swaps are excluded from hedge designations and accounted for as costs of hedging. Changes in fair value of the foreign currency basis spread are recognized in other comprehensive income to the extent that they relate to the hedged
item. For time-period related hedged items, the amount recognized in other comprehensive income is amortized to profit or loss on a straight line basis over the term of the hedging relationship.
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Fair value measurement
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The group categorizes assets and liabilities measured
at fair value into one of three levels depending on the ability to observe inputs employed in their measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are inputs that are observable, either directly or indirectly, other than quoted prices included within level 1 for the asset or liability. Level 3 inputs are unobservable inputs for the asset or liability reflecting significant modifications to observable related market data or bp’s assumptions about pricing by market participants.
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Financial statements
1.Significant accounting policies, judgements, estimates and assumptions– continued
Significant estimate and judgement: derivative financial instruments
In some cases the fair values of derivatives are estimated
using internal models due to the absence of quoted prices or other observable, market-corroborated data. This primarily applies to the group’s longer-term derivative contracts. The majority of these contracts are valued using models with inputs that include price curves for each of the different products that are built up from available active market pricing data (including volatility and correlation) and modelled using the maximum available external information. Additionally, where limited data exists for certain products, prices are determined using historical and long-term pricing relationships. The use of alternative assumptions or valuation methodologies may result in significantly different values for these derivatives. A reasonably possible change in the price assumptions used in the
models relating to index price would not have a material impact on net assets and the Group income statement primarily as a result of offsetting movements between derivative assets and liabilities. For more information, including the carrying amounts of level 3 derivatives, see Note 30.
In some cases, judgement is required to determine whether contracts to buy or sell commodities meet the definition of a derivative or to determine appropriate presentation and classification of transactions in certain cases. In particular contracts to buy and sell LNG are not considered to meet the definition as they are not considered capable of being net settled due to a lack of liquidity in the LNG market and the inability or lack of history of net settlement
and so are accounted for on an accruals basis, rather than as a derivative.
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Offsetting of financial assets and liabilities
Financial assets and liabilities are presented gross in the balance sheet unless both of the following criteria are met: the group currently has a legally enforceable right to set off the recognized amounts; and the group intends to either settle on a net basis or realize the asset and settle the liability
simultaneously. A right of set off is the group’s legal right to settle an amount payable to a creditor by applying against it an amount receivable from the same counterparty. The relevant legal jurisdiction and laws applicable to the relationships between the parties are considered when assessing whether a current legally enforceable right to set off exists.
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Provisions and contingencies
Provisions are recognized when the group has a
present legal or constructive obligation as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where appropriate, the future cash flow estimates are adjusted to reflect risks specific to the liability.
If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pre-tax risk-free rate that reflects current market assessments of the time value of money. Where discounting is used, the increase in the provision due to the passage of time is recognized within finance costs. Provisions are discounted using a nominal discount rate of i2.5%
(2019 i2.5%).
Provisions are split between amounts expected to be settled within 12 months of the balance sheet date (current) and amounts expected to be settled later (non-current).
Contingent liabilities are possible obligations whose existence will only be confirmed by future events not wholly within the control of the group, or present obligations where it is not probable that an outflow of resources will be required or
the amount of the obligation cannot be measured with sufficient reliability. Contingent liabilities are not recognized in the consolidated financial statements but are disclosed unless the possibility of an outflow of economic resources is considered remote.
Decommissioning
Liabilities for decommissioning costs are recognized when the group has an obligation to plug and abandon a well, dismantle and remove a facility or an item of plant and to restore the site on which it is located, and when a reliable estimate of that liability can be made. Where an obligation exists for a new facility or item of plant, such as oil and natural gas production or transportation facilities, this liability will be recognized on construction or installation. Similarly, where an obligation exists for a well, this liability is recognized when it is drilled. An obligation for decommissioning may also crystallize
during the period of operation of a well, facility or item of plant through a change in legislation or through a decision to terminate operations; an obligation may also arise in cases where an asset has been sold but the subsequent owner is no longer able to fulfil its decommissioning obligations, for example due to bankruptcy. The amount recognized is the present value of the estimated future expenditure determined in accordance with local conditions and requirements. The provision for the costs of decommissioning wells, production facilities and pipelines at the end of their economic lives is estimated using existing technology, at future prices, depending on the expected timing of the activity, and discounted using the nominal discount rate.
An amount equivalent to the decommissioning provision is recognized as part of the corresponding intangible asset (in the case of an exploration or appraisal well) or property, plant
and equipment. The decommissioning portion of the property, plant and equipment is subsequently depreciated at the same rate as the rest of the asset. Other than the unwinding of discount on or utilisation of the provision, any change in the present value of the estimated expenditure is reflected as an adjustment to the provision and the corresponding asset where that asset is generating or is expected to generate future economic benefits.
Environmental expenditures and liabilities
Environmental expenditures that are required in order for the group to obtain future economic benefits from its assets are capitalized as part of those assets. Expenditures that relate to an existing condition caused by past operations that do not contribute to future earnings are expensed.
Liabilities for environmental costs are recognized when a clean-up is
probable and the associated costs can be reliably estimated. Generally, the timing of recognition of these provisions coincides with the commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites.
The amount recognized is the best estimate of the expenditure required to settle the obligation. Provisions for environmental liabilities have been estimated using existing technology, at future prices and discounted using a nominal discount rate.
Emissions
Liabilities for emissions are recognized when the cumulative volumes of gases emitted by the group at the end of the reporting period exceed the allowances granted free of charge held for own use or a set baseline for emissions. The provision is measured at the best estimate of the expenditure required to settle the present obligation at the balance
sheet date. It is based on the excess of actual emissions over the free allowances held or set baseline in tonnes (or other appropriate quantity) and is valued at the actual cost of any allowances that have been purchased and held for own use on a first-in-first-out (FIFO) basis, and, if insufficient allowances are held, for the remaining requirement on the basis of the spot market price of allowances at the balance sheet date. The cost of allowances purchased to cover a shortfall is recognized separately on the balance sheet as an intangible asset unless the emission allowances acquired or generated by the group are risk-managed by the integrated supply and trading function, then they are recognized on the balance sheet as inventory.
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1.Significant accounting policies, judgements, estimates and assumptions– continued
Restructuring provisions
The reinvent bp programme, expected to reduce headcount by around 10,000 positions, has resulted in recognition of provisions where a detailed formal plan exists, and a valid expectation of risk of redundancy has been made to those affected but where the specific outcomes remain uncertain . Where formal redundancy offers have been made, the obligations for those amounts are reported as payables and,
if not, as provisions if unpaid at the year-end.
Significant judgements and estimates: provisions
The group holds provisions for the future decommissioning of oil and natural gas production facilities and pipelines at the end of their economic lives. The largest decommissioning obligations facing bp relate to the plugging and abandonment of wells and the removal and disposal of oil and natural gas platforms and pipelines around the world. Most of these decommissioning events are many years in the future and the precise requirements that will have to be met when the removal event occurs are uncertain. Decommissioning technologies and costs are constantly changing, as are political, environmental, safety and public expectations. The timing and amounts of
future cash flows are subject to significant uncertainty and estimation is required in determining the amounts of provisions to be recognized. Any changes in the expected future costs are reflected in both the provision and the asset.
If oil and natural gas production facilities and pipelines are sold to third parties, judgement is required to assess whether the new owner will be unable to meet their decommissioning obligations, whether bp would then be responsible for decommissioning, and if so the extent of that responsibility. The group has assessed that no material decommissioning provisions should be recognized as at 31 December 2020 (2019 no material provisions) for assets sold to third parties where the sale transferred the decommissioning obligation to the new owner.
Decommissioning provisions associated with downstream refineries are generally not recognized, as the potential
obligations cannot be measured, given their indeterminate settlement dates.Obligations may arise if refineries cease manufacturing operations and any such obligations would be recognized in the period when sufficient information becomes available to determine potential settlement dates.
The group performs periodic reviews of its downstream refineries for any changes in facts and circumstances including those relating to the energy transition, that might require the recognition of a decommissioning provision.
The provision for environmental liabilities is estimated based on current legal and constructive requirements, technology, price levels and expected plans for remediation. Actual costs and cash outflows can differ from current estimates because of changes in laws and regulations, public expectations, prices, discovery and analysis of site conditions and changes in clean-up technology.
The timing and amount of future expenditures relating to decommissioning and environmental liabilities are reviewed annually. The interest rate used in discounting the cash flows is reviewed quarterly. The nominal interest rate used to determine the balance sheet obligations at the end of 2020 was i2.5% (2019 i2.5%),
which was based on long-dated US government bonds. The weighted average period over which decommissioning and environmental costs are generally expected to be incurred is estimated to be approximately i18 years (2019 i18
years) and i6 years (2019 i6 years) respectively. Costs at future prices are determined by applying an inflation rate of i1.5%
(2019 i1.5%) to decommissioning costs and i2% (2019 i2%)
for all other provisions. A lower rate is applied to decommissioning as certain costs are expected to remain fixed at current or past prices.
Further information about the group’s provisions is provided in Note 23. Changes in assumptions in relation to the group's provisions could result in a material change in their carrying amounts within the next financial year. A i0.5 percentage point decrease in the nominal discount rate applied could increase the group’s provision balances by approximately
$i1.3 billion (2019 $i1.4 billion).
The pre-tax impact on the group income statement would be a charge of approximately $i0.5 billion.
The discounting impact on the group's Upstream decommissioning provisions of a two-year change in the timing of expected future decommissioning expenditures would not be material. Management currently does not consider a change of greater than two years to be reasonably possible in the next
financial year.
If all expected future decommissioning expenditures were 10% higher, the group's Upstream decommissioning provisions would increase by approximately $i1.4 billion and a pre-tax charge of approximately $i0.5 billion
would be recognized.
As described in Note 33, the group is subject to claims and actions for which no provisions have been recognized. The facts and circumstances relating to particular cases are evaluated regularly in determining whether a provision relating to a specific litigation should be recognized or revised. Accordingly, significant management judgement relating to provisions and contingent liabilities is required, since the outcome of litigation is difficult to predict.
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Employee
benefits
Wages, salaries, bonuses, social security contributions, paid annual leave and sick leave are accrued in the period in which the associated services are rendered by employees of the group. Deferred bonus arrangements that have a vesting date more than 12 months after the balance sheet date are valued on an actuarial basis using the projected unit credit method and amortized on a straight-line basis over the service period until the award vests. The accounting policies for share-based payments and for pensions and other post-retirement benefits are described below.
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Share-based
payments
Equity-settled transactions
The cost of equity-settled transactions with employees is measured by reference to the fair value of the equity instruments on the date on which they are granted and is recognized as an expense over the vesting period, which ends on the date on which the employees become fully entitled to the award. A corresponding credit is recognized within equity. Fair value is determined by using an appropriate, widely used, valuation model. In valuing equity-settled transactions, no account is taken of any vesting conditions, other than conditions linked to the price of the shares of the company (market conditions). Non-vesting conditions, such as the condition that employees contribute to a savings-related plan, are taken into account in the grant-date fair value, and failure
to meet a non-vesting condition, where this is within the control of the employee is treated as a cancellation and any remaining unrecognized cost is expensed.
For other equity-settled share-based payment transactions, the goods or services received and the corresponding increase in equity are measured at the fair value of the goods or services received unless their fair value cannot be reliably estimated. If the fair value of the goods and services received cannot be reliably estimated, the transaction is measured by reference to the fair value of the equity instruments granted.
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Financial statements
1.Significant accounting policies, judgements, estimates and assumptions– continued
Cash-settled transactions
The cost of cash-settled transactions is recognized as an expense over the vesting period, measured by reference to the fair value of the corresponding liability which is recognized on the balance sheet. The liability is remeasured
at fair value at each balance sheet date until settlement, with changes in fair value recognized in the income statement.
Pensions and other post-retirement benefits
The cost of providing benefits under the group’s defined benefit plans is determined separately for each plan using the projected unit credit method, which attributes entitlement to benefits to the current period to determine current service cost and to the current and prior periods to determine the present value of the defined benefit obligation. Past service costs, resulting from either a plan amendment or a curtailment (a reduction in future obligations as a result of a material reduction in the plan membership), are recognized immediately when the company becomes committed to a change.
Net
interest expense relating to pensions and other post-retirement benefits, which is recognized in the income statement, represents the net change in present value of plan obligations and the value of plan assets resulting from the passage of time, and is determined by applying the discount rate to the present value of the benefit obligation at the start of the year, and to the fair value of plan assets at the start of the year, taking into account expected changes in the obligation or plan assets during the year.
Remeasurements of the defined benefit liability and asset, comprising actuarial gains and losses, and the return on plan assets (excluding amounts included in net interest described above) are recognized within other comprehensive income in the period in which they occur and are not subsequently reclassified to profit and loss.
The defined benefit pension plan surplus or
deficit recognized on the balance sheet for each plan comprises the difference between the present value of the defined benefit obligation (using a discount rate based on high quality corporate bonds) and the fair value of plan assets out of which the obligations are to be settled directly. Fair value is based on market price information and, in the case of quoted securities, is the published bid price. Defined benefit pension plan surpluses are only recognized to the extent they are recoverable, either by way of a refund from the plan or reductions in future contributions to the plan.
Contributions to defined contribution plans are recognized in the income statement in the period in which they become payable.
Significant estimate: pensions and other post-retirement
benefits
Accounting for defined benefit pensions and other post-retirement benefits involves making significant estimates when measuring the group's pension plan surpluses and deficits. These estimates require assumptions to be made about many uncertainties.
Pensions and other post-retirement benefit assumptions are reviewed by management at the end of each year. These assumptions are used to determine the projected benefit obligation at the year end and hence the surpluses and deficits recorded on the group's balance sheet, and pension and other post-retirement benefit expense for the following year.
The assumptions that are the most significant to the amounts reported are the discount rate, inflation rate, salary growth and mortality levels. Assumptions about these variables are based on the environment in each country. The assumptions
used vary from year to year, with resultant effects on future net income and net assets. Changes to some of these assumptions, in particular the discount rate and inflation rate, could result in material changes to the carrying amounts of the group's pension and other post-retirement benefit obligations within the next financial year, in particular for the UK, US and Eurozone plans. Any differences between these assumptions and the actual outcome will also affect future net income and net assets.
The values ascribed to these assumptions and a sensitivity analysis of the impact of changes in the assumptions on the benefit expense and obligation used are provided in Note 24.
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Income
taxes
Income tax expense represents the sum of current tax and deferred tax.
Income tax is recognized in the income statement, except to the extent that it relates to items recognized in other comprehensive income or directly in equity, in which case the related tax is recognized in other comprehensive income or directly in equity.
Current tax is based on the taxable profit for the period. Taxable profit differs from net profit as reported in the income statement because it is determined in accordance with the rules established by the applicable taxation authorities. It therefore excludes items of income or expense that are taxable or deductible in other periods as well as items that are never taxable or deductible. The group’s liability for current tax is calculated using tax rates and laws that have been enacted or substantively enacted
by the balance sheet date.
Deferred tax is provided, using the liability method, on temporary differences at the balance sheet date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes. Deferred tax liabilities are recognized for all taxable temporary differences except:
•Where the deferred tax liability arises on the initial recognition of goodwill.
•Where the deferred tax liability arises on the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither accounting profit nor taxable profit or loss.
•In respect of taxable temporary differences associated with investments in subsidiaries
and associates and interests in joint arrangements, where the group is able to control the timing of the reversal of the temporary differences and it is probable that the temporary differences will not reverse in the foreseeable future.
Deferred tax assets are recognized for deductible temporary differences, carry-forward of unused tax credits and unused tax losses, to the extent that it is probable that taxable profit will be available against which the deductible temporary differences and the carry-forward of unused tax credits and unused tax losses can be utilized, except where the deferred tax asset relating to the deductible temporary difference arises from the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither accounting profit nor taxable profit or loss. In respect of deductible temporary differences associated with investments
in subsidiaries and associates and interests in joint arrangements, deferred tax assets are recognized only to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profit will be available against which the temporary differences can be utilized.
The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable or increased to the extent that it is probable that sufficient taxable profit will be available to allow all or part of the deferred tax asset to be utilized.
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1.Significant accounting policies, judgements, estimates and assumptions– continued
Deferred tax assets and liabilities are measured at the tax rates that are expected to apply in the period when the asset is realized or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the balance sheet date. Deferred tax assets and liabilities are not discounted.
Deferred tax assets and liabilities are offset only when there is a legally enforceable right to set
off current tax assets against current tax liabilities and when the deferred tax assets and liabilities relate to income taxes levied by the same taxation authority on either the same taxable entity or different taxable entities where there is an intention to settle the current tax assets and liabilities on a net basis or to realize the assets and settle the liabilities simultaneously.
Where tax treatments are uncertain, if it is considered probable that a taxation authority will accept the group's proposed tax treatment, income taxes are recognized consistent with the group's income tax filings. If it is not considered probable, the uncertainty is reflected within the carrying amount of the applicable tax asset or liability using either the most likely amount or an expected value, depending on which method better predicts the resolution of the uncertainty.
The computation of the
group’s income tax expense and liability involves the interpretation of applicable tax laws and regulations in many jurisdictions throughout the world. The resolution of tax positions taken by the group, through negotiations with relevant tax authorities or through litigation, can take several years to complete and in some cases it is difficult to predict the ultimate outcome. Therefore, judgement is required to determine whether provisions for income taxes are required and, if so, estimation is required of the amounts that could be payable.
In addition, the group has carry-forward tax losses and tax credits in certain taxing jurisdictions that are available to offset against future taxable profit. However, deferred tax assets are recognized only to the extent that it is probable that taxable profit will be available against which the unused tax losses or tax credits can be utilized. Management judgement is exercised in assessing
whether this is the case and estimates are required to be made of the amount of future taxable profits that will be available.Such judgements are inherently impacted by estimates affecting future taxable profits such as oil and natural gas prices and decommissioning expenditure, see significant judgements and estimates: recoverability of asset carrying values and provisions
Management do not assess there to be a significant risk of a material change to the group’s tax provisioning or recognition of deferred tax assets within the next financial year, however the tax position remains inherently uncertain and therefore subject to change. To the extent that actual outcomes differ from management’s estimates, income tax charges or credits, and changes in current and deferred tax assets or liabilities, may arise in future periods. For more information see Note 9 and Note 33.
Judgement
is also required when determining whether a particular tax is an income tax or another type of tax (for example a production tax). Accounting for deferred tax is applied to income taxes as described above, but is not applied to other types of taxes; rather such taxes are recognized in the income statement in accordance with the applicable accounting policy such as Provisions and contingencies. No new significant judgements were made in 2020 in this regard.
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Customs duties and sales taxes
Customs
duties and sales taxes that are passed on or charged to customers are excluded from revenues and expenses. Assets and liabilities are recognized net of the amount of customs duties or sales tax except:
•Customs duties or sales taxes incurred on the purchase of goods and services which are not recoverable from the taxation authority are recognized as part of the cost of acquisition of the asset.
•Receivables and payables are stated with the amount of customs duty or sales tax included.
The net amount of sales tax recoverable from, or payable to, the taxation authority is included within receivables or payables in the balance sheet.
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Own
equity instruments – treasury shares
The group’s holdings in its own equity instruments are shown as deductions from shareholders’ equity. Treasury shares represent bp shares repurchased and available for specific and limited purposes. For accounting purposes, shares held in Employee Share Ownership Plans (ESOPs) to meet the future requirements of the employee share-based payment plans are treated in the same manner as treasury shares and are, therefore, included in the consolidated financial statements as treasury shares. The cost of treasury shares subsequently sold or reissued is calculated on a weighted-average basis. Consideration, if any, received for the sale of such shares is also recognized in equity. No gain or loss is recognized in the income statement on the purchase, sale, issue or cancellation of equity shares. Shares repurchased under the share buy-back programme which are immediately cancelled are not shown
as treasury shares, but are shown as a deduction from the profit and loss account reserve in the group statement of changes in equity.
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Revenueand other income
Revenue from contracts with customers is recognized when or as the group satisfies a performance obligation by transferring control of a promised
good or service to a customer. The transfer of control of oil, natural gas, natural gas liquids, LNG, petroleum and chemical products, and other items usually coincides with title passing to the customer and the customer taking physical possession. The group principally satisfies its performance obligations at a point in time; the amounts of revenue recognized relating to performance obligations satisfied over time are not significant.
When, or as, a performance obligation is satisfied, the group recognizes as revenue the amount of the transaction price that is allocated to that performance obligation. The transaction price is the amount of consideration to which the group expects to be entitled. The transaction price is allocated to the performance obligations in the contract based on standalone selling prices of the goods or services
promised.
Contracts for the sale of commodities are typically priced by reference to quoted prices. Revenue from term commodity contracts is recognized based on the contractual pricing provisions for each delivery. Certain of these contracts have pricing terms based on prices at a point in time after delivery has been made. Revenue from such contracts is initially recognized based on relevant prices at the time of delivery and subsequently adjusted as appropriate. All revenue from these contracts,
both that recognized at the time of delivery and that from post-delivery price adjustments, is disclosed as revenue from contracts with customers.
Certain forward contracts entered into by the group that result in physical delivery of products such as crude oil, natural gas and refined products are required to be accounted for as derivative financial instruments. Revenue recognized relating to such contracts when physical delivery occurs is measured at the contractual transaction price plus the carrying amount of the related derivative at the date of settlement and presented as other operating revenues. Changes in the fair value of derivative assets and liabilities
prior to physical delivery are also classified as other operating revenues. See also Other significant accounting policy changes - IFRIC agenda decision on IFRS 9 'Financial instruments' below.
174
bp Annual Report and Form 20-F 2020
Financial
statements
1.Significant accounting policies, judgements, estimates and assumptions– continued
Where forward sale and purchase contracts for oil, natural gas or power have been determined to be for short-term trading purposes, the associated sales and purchases are reported net within sales and other operating revenues whether or not physical delivery has occurred.
Physical exchanges with counterparties in the same line of business in order to facilitate sales to customers are reported net, as are sales and purchases made with a common counterparty, as part of an arrangement similar to a physical exchange.
Where
the group acts as agent on behalf of a third party to procure or market energy commodities, any associated fee income is recognized but no purchase or sale is recorded.
Interest income is recognized as the interest accrues (using the effective interest rate, that is, the rate that exactly discounts estimated future cash receipts through the expected life of the financial instrument to the net carrying amount of the financial asset).
Dividend income from investments is recognized when the shareholders’ right to receive the payment is established.
Contract asset and contract liability balances are included within amounts presented for trade receivables and other
payables respectively.
i
Finance costs
Finance costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use, are added to the cost of those assets until such time as the assets are substantially ready for their intended use. All other finance costs are recognized in the income statement in the period in which they are incurred.
i
Updates
to significant accounting policies
Impact of new International Financial Reporting Standards
bp adopted ‘Interest Rate Benchmark Reform – Phase I – Amendments to IFRS 9 ‘Financial instruments’ and IFRS 7 ‘Financial instruments: Disclosures’’ with effect from 1 January 2020. There are no other new or amended standards or interpretations adopted during the year that have a significant impact on the consolidated financial statements.
'Interest Rate Benchmark Reform – Phase I’
Financial authorities in the US, UK, EU and other territories are currently undertaking reviews of key interest rate benchmarks such as the London Inter-bank Offered Rate (LIBOR) with a view to replacing them with alternative benchmarks. Uncertainty around the method and timing of transition
from Inter-bank Offered Rates (IBORs) to alternative risk-free rates (RfRs) may impact the assessment of whether hedge accounting can be applied to certain hedging relationships.
This first phase of amendments to IFRS 9 provide temporary relief from applying specific hedge accounting requirements to hedging relationships directly affected by interest rate benchmark reforms.
In accordance with the transition provisions, the amendments have been adopted retrospectively to hedging relationships that existed at the start of the current reporting period and have been applied to new hedging relationships designated after that date.
The reliefs have meant that the uncertainty over the interest rate benchmark reforms has not resulted in discontinuation of hedge accounting for any of bp’s fair value hedges.
See
Note 29 Financial instruments and financial risk factors - interest rate risk and Note 30 Derivative financial instruments - Fair value hedges for further information.
Impact of new International Financial Reporting Standards - Not yet adopted
The following pronouncements from the IASB have not been adopted by the group in these financial statements as they will only become effective for future financial reporting periods. There are no other standards, amendments or interpretations in issue but not yet adopted that the directors anticipate will have a material effect on the reported income or net assets of the group.
IFRS 17 'Insurance Contracts'
provides a new general model for accounting for contracts where the issuer accepts significant insurance risk from another party and agrees to compensate that party if a future uncertain event adversely affects them. IFRS 17 replaces IFRS 4 'Insurance Contracts' and will be effective for bp for the financial reporting period commencing 1 January 2023. The standard has not yet been endorsed by the UK and the EU. bp's assessment of the impact of IFRS 17 is at an initial stage but it is not expected to have a significant effect on future financial reporting.
‘Interest Rate Benchmark Reform – Phase II’
Amendments to IFRS 9, IFRS 7, IFRS 4 and IFRS 16 ‘Leases’ were issued by the IASB in August 2020 to provide practical
expedients and reliefs in relation to modifications of financial instruments and leases that arise from transition from IBORs to RFRs. Phase II also provides further reliefs to hedge accounting requirements. These amendments were effective for bp from 1 January 2021. The amendments have been endorsed by the UK and by the EU.
bp’s working group on interest rate benchmark reform is monitoring and managing the transition to alternative benchmark rates and is currently assessing the impact on contracts and arrangements that are linked to existing interest rate benchmarks for example, borrowings, leases and derivative contracts. bp is also participating on external committees and task forces dedicated to interest rate benchmark reform.
In March 2019, IFRIC issued an agenda decision on the application of IFRS 9 to the physical settlement of contracts to buy or sell a non-financial item, such as commodities, that are not accounted for as 'own-use' contracts. IFRIC concluded that such contracts are settled by the delivery or receipt of a non-financial item in exchange for both cash and the settlement of the derivative asset or liability.
bp
routinely enters into transactions for the sale and purchase of commodities that are physically settled and meet the definition of a derivative financial instrument. As described in the group's accounting policy for revenue in bp Annual Report and Form 20-F 2019, revenue recognized at the time such contracts were physically settled was measured at the contractual transaction price and was presented together with revenue from contracts with customers in those financial statements.
bp
Annual Report and Form 20-F 2020
175
1.Significant accounting policies, judgements, estimates and assumptions– continued
bp changed its accounting policy for these contracts, in accordance with the conclusions included in the agenda decision, with effect from 1 April 2020, as follows:
•Revenues and purchases from such contracts are measured
at the contractual transaction price plus the carrying amount of the related derivative at the date of settlement. Realized derivative gains and losses on physically settled derivative contracts are included in other revenues.
•There is no significant effect on current period or comparative information for ‘Sales and other operating revenues’ and ‘Purchases’ as presented in the group income statement, therefore no comparative information has been re-stated.
•There is no significant effect on net assets or on comparative information for ‘Profit before taxation’ or ‘Profit after taxation’ as presented in the group income statement.
i
In
addition, bp chose to change its presentation of revenues from physically settled derivative sales contracts from 1 January 2020. Revenues from physically settled derivative sales contracts are no longer presented together with revenue from contracts with customers. In these financial statements they are now presented as other revenues. Comparative information in Note 6 for revenue from contracts with customers and other revenues have been re-presented to align with the current period as set out below.
$
million
2019 (previously reported)
2019 (re-presented – see note 6)
Presentational adjustments
2018 (previously reported)
2018 (re-presented – see note 6)
Presentational adjustments
Crude oil
i62,130
i9,141
i52,989
i65,276
i10,331
i54,945
Oil
products
i180,528
i102,408
i78,120
i195,466
i108,515
i86,951
Natural
gas, LNG and NGLs
i20,167
i18,909
i1,258
i21,745
i20,494
i1,251
Non-oil
products and other revenues from contracts with customers
Voluntary
changes to significant accounting policies - not yet adopted
Net presentation of revenues and purchases relating to physically settled derivative contracts from 1 January 2021
As described above, bp routinely enters into transactions for the sale and purchase of commodities that are physically settled and meet the definition of a derivative financial instrument. These contracts are within the scope of IFRS 9 and as such, prior to settlement, changes in the fair value of these derivative contracts are presented as gains and losses within other operating revenues. The group currently presents revenues and purchases for such
contracts on a gross basis in the group income statement upon physical settlement. These transactions have historically represented a substantial portion of the revenues and purchases reported in the group’s consolidated financial statements.
The change in strategic direction of the group supported by organisational changes to implement the strategy from 1 January 2021, results in the group determining that the revenue and corresponding purchases relating to such transactions should be presented net as gains or losses within other operating revenues. Additionally the group’s trading activity has continued to evolve over time from one of capturing third party physical trades to provide flow assurance to one with increasing levels of optimisation, taking advantage of price volatility and fluctuations in demand and supply, which will continue
under the new strategy, further supporting the change in presentation. The new presentation provides reliable and more relevant information for users of the accounts as the group’s revenue recognition will be more closely aligned with its assessment of ‘Scope 3’ emissions from its products, its ‘Net Zero’ ambition and how management monitors and manages performance of such contracts. Comparative information for Sales and other operating revenues and purchases for 2019 and 2020 will be restated and will be presented under the new policy alongside group’s 2021 financial information.
Change in segmentation
During the first quarter of 2021, the group's reportable segments changed consistent with a change in the way that resources are allocated and performance is assessed by the chief operating decision
maker, who for bp is the group chief executive, from that date. From the first quarter of 2021, the group's reportable are gas & low carbon energy, oil production & operations, customers & products, and Rosneft. At 31 December 2020, the group's reportable segments were Upstream, Downstream and Rosneft.
Gas & low carbon energy comprises regions with upstream businesses that predominantly produce natural gas, gas trading activities and the group's renewables businesses, including biofuels, solar and wind. Gas producing regions were previously in the Upstream segment. The group's renewables businesses were previously part of 'Other businesses and corporate'.
Oil production & operations comprises regions with upstream activities that predominantly produce crude oil. These activities were previously in the Upstream segment.
Customers
& products comprises the group's convenience and mobility business, which manages the sale of fuels to wholesale and retail customers, convenience products, aviation fuels, and Castrol lubricants; and refining, supply and trading. The petrochemicals business will also be reported in restated comparative information as part of the customers and products segment up to its sale in December 2020. The customers & products segment is, therefore, substantially unchanged from the former Downstream segment with the exception of the Petrochemicals disposal.
The Rosneft segment is unchanged and continues to include equity-accounted earnings from the group's investment in Rosneft.
The segment measure of profit or loss continues to be replacement cost profit or loss before interest and tax, which reflects the replacement cost of supplies by excluding from profit or loss before interest
and tax inventory holding gains and losses. See Note 5 for further information.
In the group's financial reporting for 2021, comparative information for 2019 and 2020 will be restated to reflect the changes in reportable segments. Reporting under the new segment structure will begin with the first quarter 2021 interim financial statements.
Segmental information presented in these financial statements is based on the segment structure as at 31 December 2020.
176
bp
Annual Report and Form 20-F 2020
Financial statements
2.iNon-current
assets held for sale
The carrying amount of assets classified as held for sale at 31 December 2020 is $i1,326 million (2019 $i7,465 million),
with associated liabilities of $i46 million (2019 $i1,393 million).
Upstream
segment
The balance consists primarily of a i20% participating interest from bp’s i60%
participating interest in Block 61 in Oman. As announced on 1 February 2021, bp has agreed to sell this interest to PTT Exploration and Production Public Company Limited of Thailand for a total consideration of up to $i2.6 billion, subject to final adjustments. Under the terms of the agreement, bp will receive $i2,450 million
on completion, with up to an additional $i140 million receivable contingent on pre-agreed future conditions. Subject to approvals, the transaction is expected to complete during 2021. Assets of $i1,298 million
and associated liabilities of $i10 million have been classified as held for sale in the group balance sheet at 31 December 2020.
Transactions that have been classified as held for sale during 2020, but were completed by 31 December 2020, are described below.
Downstream segment
On 29 June 2020 bp announced that it had agreed to sell its global petrochemicals business to INEOS
for a total consideration of $i5 billion, subject to customary closing adjustments. The assets and liabilities of the business were classified as held for sale from that date until the disposal completed on 31 December 2020. Under the terms of the agreement, INEOS paid bp a deposit of $i400 million
and a further $i3.6 billion on completion less $i0.1 billion
of third-party indebtedness remaining in petrochemicals on completion. The remaining $i1 billion was received in February 2021. The business had interests in manufacturing plants in Asia, Europe and the US, including interests held in equity-accounted entities. See note 4 for further information.
Upstream segment
On 27 August 2019, bp announced that it had agreed to sell its Alaska operations
and interests to Hilcorp Energy for up to $i5.6 billion, subject to customary closing adjustments. The sale included bp’s upstream and midstream business in the state, including BP Exploration (Alaska) Inc., which owned all of bp’s upstream oil and gas interests in Alaska, and BP Pipelines (Alaska) Inc.’s i49%
interest in the Trans Alaska Pipeline System (TAPS). These assets and associated liabilities were classified as held for sale in the 31 December 2019 group balance sheet. The disposal of BP Exploration (Alaska) Inc. completed on 30 June 2020. The disposal of TAPS completed on 18 December 2020.
bp received $i800 million prior to or on completion of the disposals and has recognized a loan note with a principal amount of $i2,100 million
receivable from Hilcorp. The group has also recognized other assets totalling $i1,722 million as at 31 December 2020, principally in relation to the ‘earn-out’ provisions of the agreement. See note 4 for information on impairment charges relating to the Alaska business.
bp retained decommissioning liability relating to the TAPS, which will be partially offset by a i30%
cost reimbursement from Hilcorp when incurred.
In November 2019, bp agreed to sell its interests in the San Juan basin in Colorado and New Mexico to IKAV.These assets and associated liabilities were classified as held for sale in the 31 December 2019 group balance sheet. The transaction completed on 28 February 2020.
i
The total assets and liabilities held for sale at 31 December 2020 and 2019, which are all in the Upstream segment, are set out in the table below.
$
million
2020
2019
Property, plant and equipment
i1,099
i6,359
Goodwill
i199
i—
Intangible
assets
i—
i610
Investments
in associates
i—
i43
Inventories
i—
i318
Trade
and other receivables
i28
i135
Assets
classified as held for sale
i1,326
i7,465
Trade
and other payables
(i36)
(i33)
Lease
liabilities
i—
(i280)
Provisions
(i10)
(i1,012)
Defined
benefit pension plan and other post-retirement benefit plan deficits
i—
(i68)
Liabilities
directly associated with assets classified as held for sale
(i46)
(i1,393)
/
3.iBusiness combinations and other significant transactions
Business combinations
2020
The group undertook a number of business combinations during 2020. The fair value of the net assets (including goodwill) and non-controlling interests recognized were $i617
million and $i574 million, respectively. These principally related to an acquisition in our US Fuels business.
2019
As agreed as part of the original transaction, $i3,480
million was paid in 2019 in respect of the 2018 acquisition of Petrohawk Energy Corporation from BHP Billiton. A number of other individually insignificant business combinations were also undertaken by bp in 2019.
bp Annual Report and Form 20-F 2020
177
4.iDisposals and impairment
i
The
following amounts were recognized in the income statement in respect of disposals and impairments.
$ million
2020
2019
2018
Gains on sale of businesses and fixed
assets
Upstream
i360
i143
i437
Downstream
i2,320
i50
i15
Other
businesses and corporate
i194
i—
i4
i2,874
i193
i456
$
million
2020
2019
2018
Losses on sale of businesses and fixed assets, and closures
Upstream
i383
i415
i707
Downstream
i296
i57
i59
Other
businesses and corporate
i2
i887
i11
i681
i1,359
i777
Impairment
losses
Upstream
i12,917
i6,752
i400
Downstream
i840
i65
i12
Other
businesses and corporate
i32
i30
i254
i13,789
i6,847
i666
Impairment
reversals
Upstream
(i86)
(i131)
(i580)
Downstream
i—
i—
(i2)
Other
businesses and corporate
(i3)
i—
(i1)
(i89)
(i131)
(i583)
Impairment
and losses on sale of businesses and fixed assets, and closures
i14,381
i8,075
i860
/
Disposals
i
Disposal
proceeds and principal gains and losses on disposals by segment are described below.
$ million
2020
2019
2018
Proceeds from disposals of fixed assets
i491
i500
i940
Proceeds
from disposals of businesses, net of cash disposed
i4,989
i1,701
i1,911
i5,480
i2,201
i2,851
By
business
Upstream
i1,175
i2,048
i2,145
Downstream
i3,959
i152
i120
Other
businesses and corporate
i346
i1
i586
i5,480
i2,201
i2,851
/
Proceeds
from disposals of business in 2020 includes $i3,888 million in respect of the disposal of the Petrochemical business and $i347 million
in respect of the disposal of the Alaska business. At 31 December 2020, deferred consideration relating to disposals amounted to $i1,291 million receivable within one year (2019 $i159
million and 2018 $i35 million) and $i2,402
million receivable after one year (2019 $i125 million and 2018 $i304
million). The deferred consideration principally relates to the disposals of our Petrochemical and Alaskan businesses. In addition, contingent consideration receivable relating to disposals amounted to $i1,999 million at 31 December 2020 (2019 $i598
million and 2018 $i893 million).The contingent consideration at 31 December 2020 relates to the disposal of our Alaskan business and prior period disposals in the North Sea. These amounts of contingent consideration are reported within Other investments on the group balance sheet - see Note 18 for further information.
Gains and losses on sale of businesses and fixed assets, and
closures
Upstream
In 2020, gains principally resulted from adjustments to disposals in prior periods. Gains include $i130 million from the disposal of our Alaska operations and interests and $i166 million
fair value movements in relation to deferred and contingent consideration in relation to the Alaska disposal and prior disposals in the North Sea. Losses included $i134 million fair value movements in relation to deferred and contingent consideration arising from prior period disposals in the North Sea, $i120 million
in relation to the likely disposal of an exploration asset, and $i78 million from the disposal of certain properties in the US.
In 2019, losses included $i191 million
fair value movements in relation to contingent consideration arising from the prior period disposal of the Bruce, Keith and Devenick assets and $i171 million in relation to severance costs associated with the divestment of our Alaskan business.
In 2018, gains principally resulted from the disposal of interests in the Bruce, Keith and Rhum fields in the UK North
Sea, from the disposal of certain properties in the US, and from adjustments to disposals in prior periods. Losses included $i335 million resulting from the disposal of our interest in the Magnus field and associated assets in the UK North Sea, $i221 million
from the disposal of our interest in the Greater Kuparuk Area in the US, and adjustments to disposals in prior periods.
178
bp Annual Report and Form 20-F 2020
Financial
statements
4. Disposals and impairment – continued
Downstream
In 2020, gains principally resulted from the $i2.3 billion gain recognised on the disposal of our Petrochemicals business which completed in December 2020. Losses included
$i229 million in relation to cessation of manufacturing operations at the Kwinana Refinery following the decision to cease fuel production.
Other businesses and corporate
In 2020 the gain on disposal of businesses and fixed assets was principally in respect of the sale and leaseback of our St James's Square London headquarters -
see Note 28 for further information.
In 2019 losses on disposal of businesses and fixed assets were principally in respect of the reclassification of accumulated foreign exchange losses from reserves to the income statement upon the contribution of our Brazilian biofuels business to a new 50:50 joint venture BP Bunge Bioenergia.
In 2018 proceeds from disposals were principally in respect of life insurance policies in the US and wind farms within our US wind business.
Summarized financial information relating to the sale of businesses is shown in the table below.
The principal transactions categorized as a business disposal in 2020 were the sales of our Petrochemical and Alaskan businesses. See Note 2 for further information.
The principal transaction
categorized as a business disposal in 2019 was the sale of our interests in the Gulf of Suez oil concessions in Egypt.
The principal transaction categorized as a business disposal in 2018 was the disposal of our interest in the Greater Kuparuk Area in the US.
i
$
million
2020
2019
2018
Alaska
Petrochemicals
Other
Total
Non-current assets
i5,143
i2,592
i1,357
i9,092
i1,653
i3,274
Current
assets
i693
i846
i—
i1,539
i507
i173
Non-current
liabilities
(i923)
(i178)
(i538)
(i1,639)
(i257)
(i250)
Current
liabilities
(i344)
(i425)
(i13)
(i782)
(i108)
(i97)
Total
carrying amount of net assets disposed
i4,569
i2,835
i806
i8,210
i1,795
i3,100
Recycling
of foreign exchange on disposal
i—
(i331)
i3
(i328)
i880
i—
Costs
on disposal
(i6)
(i25)
i44
i13
i190
i3
i4,563
i2,479
i853
i7,895
i2,865
i3,103
Gains
(losses) on sale of businesses
i260
i2,414
(i104)
i2,570
(i1,190)
(i221)
Total
consideration
i4,823
i4,893
i749
i10,465
i1,675
i2,882
Non-cash
consideration
(i219)
i—
i—
(i219)
(i938)
(i282)
Consideration
received (receivable)a
(i4,257)
(i1,005)
i5
(i5,257)
i964
(i689)
Proceeds
from the sale of businesses, net of cash disposedb
i347
i3,888
i754
i4,989
i1,701
i1,911
a
In 2019 $i633 million relates to deposits received in advance of the disposal of our Alaska business and certain assets in our BPX business.
b Proceeds are stated net of cash and cash equivalents disposed of $i101
million (2019 $i30 million and 2018 $i15
million).
/
Impairments
Impairment losses and impairment reversals in each segment are described below. For information on significant estimates and judgements made in relation to impairments see Impairment of property, plant and equipment, intangibles and goodwill within Note 1. See also Note 12, and Note 15 for further information on impairments by asset category.
Upstream
Impairment losses and reversals in all years relate primarily to producing and midstream assets.
The 2020 impairment loss of $i12,917
million primarily relates to losses incurred in respect of producing and development assets in the UK North Sea ($i2,796 million), the US ($i2,744 million), Trinidad ($i2,416
million), Mauritania and Senegal ($i1,909 million), India ($i1,313 million) and Canada ($i865
million). Impairment losses were primarily driven by a reduction in bp’s future oil and gas price assumptions and, to a lesser extent, certain technical reserves revisions. The recoverable amount of the impaired CGUs in total is $33,415 million.
The principal CGUs on which significant impairment losses were incurred in 2020 were $i1,909 million for Tortue in Mauritania and Senegal; $i1,313
million for KGD6 in India; $i1,181 million for Schiehallion in the UK North Sea; $i1,044 million for Mahogany in Trinidad, $i960
million for Cassia in Trinidad; $i1,011 million for Hawkville in BPX Energy; $i747 million for ETAP in the UK North Sea and $i742 million
for Sunrise in Canada. The recoverable amount for each of these CGUs was their value in use, which in total was $i13,200 million. In addition, impairment losses of $i939 million
were incurred relating to the disposal of bp’s business in Alaska. The recoverable amount of the Alaska business was its fair value less costs of disposal; see note 2 for further information.
The 2019 impairment losses of $i6,752 million related to various assets, with the most significant charges arising in the US. Impairment losses arose primarily as a result of the decision to dispose of certain assets, including $i4,703
million in relation to completed and expected disposals in BPX Energy and $i1,264 million relating to the expected disposal of our Alaskan business; of these amounts $i355
million primarily relates to impairment of associated goodwill.
The 2018 impairment losses of $i400 million related to a number of different assets, with the most significant charges arising in Australia and the US. Impairment losses arose primarily as a result of changes to project activity, asset obsolescence and the decision to dispose of certain assets. The 2018 impairment reversals of $i580
million related to a number of different assets, with the most significant reversals arising in the North Sea and Angola following a change to decommissioning cost estimates.
Downstream
Impairment losses totalling $i840 million, $i65
million, and $i12 million were recognized in 2020, 2019 and 2018 respectively. The amount for 2020 principally relates to portfolio changes in the fuels business, including the conversion of Kwinana refinery to an import terminal. None of the impairment charges were individually material.
bp
Annual Report and Form 20-F 2020
179
4. Disposals and impairment – continued
Other businesses and corporate
Impairment losses totalling $i32 million, $i30
million, and $i254 million were recognized in 2020, 2019 and 2018 respectively. The amount for 2018 is in respect of assets within our US wind business in advance of their disposal in December 2018.
5.iSegmental
analysis
The group’s organizational structure reflects the various activities in which bp is engaged. At 31 December 2020, bp had ithree reportable segments: Upstream, Downstream and Rosneft.
Upstream’s activities include oil and natural gas exploration, field development and production; midstream transportation, storage and processing; and the marketing and trading of natural gas, including liquefied natural gas (LNG), together with power and
natural gas liquids (NGLs).
Downstream’s activities include the refining, manufacturing, marketing, transportation, and supply and trading of crude oil, petroleum, petrochemicals products and related services to wholesale and retail customers.
bp’s interest in Rosneft is accounted for using the equity method and is reported as a separate operating segment, reflecting the way in which the investment is managed.
Other businesses and corporate comprises the biofuels and wind businesses, the group’s shipping and treasury functions, and corporate activities worldwide.
The accounting policies of the operating segments are the same as the group’s accounting policies described in Note 1. However, IFRS requires that the measure of profit or loss disclosed for each operating segment is the measure that is
provided regularly to the chief operating decision maker for the purposes of performance assessment and resource allocation. For bp, this measure of profit or loss is replacement cost profit or loss before interest and tax which reflects the replacement cost of supplies by excluding from profit or loss before interest and tax inventory holding gains and lossesa. Replacement cost profit or loss before interest and tax for the group is not a recognized measure under IFRS.
Sales between segments are made at prices that approximate market prices, taking into account the volumes involved. Segment revenues and segment results include transactions between business segments. These transactions and any unrealized profits and losses are eliminated on consolidation, unless unrealized losses provide evidence of an impairment of the asset transferred. Sales to external customers by region are
based on the location of the group subsidiary which made the sale. The UK region includes the UK-based international activities of Downstream.
All surpluses and deficits recognized on the group balance sheet in respect of pension and other post-retirement benefit plans are allocated to Other businesses and corporate. However, the periodic expense relating to these plans is allocated to the operating segments based upon the business in which the employees work.
Certain financial information is provided separately for the US as this is an individually material country for bp, and for the UK as this is bp’s country of domicile.
In February 2020, bp announced plans for a reorganization of the group’s organizational structure. The group’s segmental reporting structure as described above remained in place throughout 2020. Changes to this structure,
as described in Note 1 - Voluntary changes to significant accounting policies - not yet adopted, came into effect from 1 January 2021.
a Inventory
holding gains and losses represent the difference between the cost of sales calculated using the replacement cost of inventory and the cost of sales calculated on the first-in first-out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting, the cost of inventory charged to the income statement is based on its historical cost of purchase or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant distorting effect on reported income. The amounts disclosed represent the difference between the charge to the income statement for inventory on a FIFO basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen based on the replacement cost of inventory. For this purpose, the replacement cost of inventory is calculated using data from each
operation’s production and manufacturing system, either on a monthly basis, or separately for each transaction where the system allows this approach. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions.
180
bp Annual Report and Form 20-F 2020
Financial
statements
5.Segmental analysis– continued
i
$
million
2020
By business
Upstream
Downstream
Rosneft
Other businesses and corporate
Consolidation adjustment and eliminations
Total group
Segment revenues
Sales
and other operating revenues
i34,197
i162,974
i—
i1,716
(i18,521)
i180,366
Less:
sales and other operating revenues between segments
(i17,130)
(i158)
i—
(i1,233)
i18,521
i—
Third
party sales and other operating revenues
i17,067
i162,816
i—
i483
i—
i180,366
Earnings
from joint ventures and associates – after interest and tax
(i268)
i214
(i229)
(i120)
i—
(i403)
Segment
results
Replacement cost profit (loss) before interest and taxation
(i21,547)
i3,418
(i149)
(i683)
i89
(i18,872)
Inventory
holding gains (losses)a
i17
(i2,796)
(i89)
i—
i—
(i2,868)
Profit
(loss) before interest and taxation
(i21,530)
i622
(i238)
(i683)
i89
(i21,740)
Finance
costs
(i3,115)
Net finance expense relating to pensions and other post-retirement benefits
(i33)
Profit
before taxation
(i24,888)
Other income statement items
Depreciation,
depletion and amortization
US
i3,772
i1,359
i—
i63
i—
i5,194
Non-US
i7,447
i1,631
i—
i617
i—
i9,695
Charges
for provisions, net of write-back of unused provisions, including change in discount rate
i56
i1,903
i—
i543
i—
i2,502
Segment
assets
Investments in joint ventures and associates
i10,749
i3,671
i11,808
i1,109
i—
i27,337
Additions
to non-current assetsb
i8,743
i5,359
i—
i655
i—
i14,757
a See
explanation of inventory holding gains and losses on page 180.
b Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.
$
million
2019
By business
Upstream
Downstream
Rosneft
Other businesses and corporate
Consolidation adjustment and eliminations
Total group
Segment
revenues
Sales and other operating revenues
i54,501
i250,897
i—
i1,788
(i28,789)
i278,397
Less:
sales and other operating revenues between segments
(i27,034)
(i973)
i—
(i782)
i28,789
i—
Third
party sales and other operating revenues
i27,467
i249,924
i—
i1,006
i—
i278,397
Earnings
from joint ventures and associates – after interest and tax
i603
i374
i2,295
(i15)
i—
i3,257
Segment
results
Replacement cost profit (loss) before interest and taxation
i4,917
i6,502
i2,316
(i2,771)
i75
i11,039
Inventory
holding gains (losses)a
(i8)
i685
(i10)
i—
i—
i667
Profit
(loss) before interest and taxation
i4,909
i7,187
i2,306
(i2,771)
i75
i11,706
Finance
costs
(i3,489)
Net finance expense relating to pensions and other post-retirement benefits
(i63)
Profit
before taxation
i8,154
Other income statement items
Depreciation,
depletion and amortization
US
i4,672
i1,335
i—
i55
i—
i6,062
Non-US
i9,560
i1,586
i—
i572
i—
i11,718
Charges
for provisions, net of write-back of unused provisions, including change in discount rate
i118
i507
i—
i560
i—
i1,185
Segment
assets
Investments in joint ventures and associates
i12,196
i3,609
i12,927
i1,593
i—
i30,325
Additions
to non-current assetsb
i16,254
i4,014
i—
i2,345
i—
i22,613
a See
explanation of inventory holding gains and losses on page 180.
b Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.
/
bp Annual Report and Form 20-F 2020
181
5.Segmental analysis– continued
$ million
2018
By
business
Upstream
Downstream
Rosneft
Other businesses and corporate
Consolidation adjustment and eliminations
Total group
Segment revenues
Sales and other
operating revenues
i56,399
i270,689
i—
i1,678
(i30,010)
i298,756
Less:
sales and other operating revenues between segments
(i28,565)
(i574)
i—
(i871)
i30,010
i—
Third
party sales and other operating revenues
i27,834
i270,115
i—
i807
i—
i298,756
Earnings
from joint ventures and associates – after interest and tax
i951
i589
i2,283
(i70)
i—
i3,753
Segment
results
Replacement cost profit (loss) before interest and taxation
i14,328
i6,940
i2,221
(i3,521)
i211
i20,179
Inventory
holding gains (losses)a
(i6)
(i862)
i67
i—
i—
(i801)
Profit
(loss) before interest and taxation
i14,322
i6,078
i2,288
(i3,521)
i211
i19,378
Finance
costs
(i2,528)
Net finance expense relating to pensions and other post-retirement benefits
(i127)
Profit
before taxation
i16,723
Other income statement items
Depreciation,
depletion and amortization
US
i4,211
i900
i—
i59
i—
i5,170
Non-US
i8,907
i1,177
i—
i203
i—
i10,287
Charges
for provisions, net of write-back of unused provisions, including change in discount rate
i355
i834
i—
i1,557
i—
i2,746
Segment
assets
Investments in joint ventures and associates
i12,785
i2,772
i10,074
i689
i—
i26,320
Additions
to non-current assetsb c
i24,266
i3,609
i—
i477
i—
i28,352
a See
explanation of inventory holding gains and losses on page 180.
b Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.
c Amounts have been restated to include acquisitions.
i
$
million
2020
By geographical area
US
Non-US
Total
Revenues
Third party sales and other operating revenuesa
i55,611
i124,755
i180,366
Other
income statement items
Production and similar taxes
i57
i638
i695
Non-current
assets
Non-current assetsbc
i52,493
i108,786
i161,279
a Non-US
region includes UK $i42,729 million
b Non-US region includes UK $i19,583
million
c Includes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments.
$ million
2019
By
geographical area
US
Non-US
Total
Revenues
Third party sales and other operating revenuesa
i89,334
i189,063
i278,397
Other
income statement items
Production and similar taxes
i315
i1,232
i1,547
Non-current
assets
Non-current assetsbc
i57,757
i133,398
i191,155
a Non-US
region includes UK $i63,194 million.
b Non-US region includes UK $i22,881
million.
c Includes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments.
/
182
bp Annual Report and Form 20-F 2020
Financial
statements
5.Segmental analysis– continued
$ million
2018
By
geographical area
US
Non-US
Total
Revenues
Third party sales and other operating revenuesa
i98,066
i200,690
i298,756
Other
income statement items
Production and similar taxes
i369
i1,167
i1,536
Non-current
assets
Non-current assetsb c
i68,188
i124,060
i192,248
a Non-US
region includes UK $i65,630 million.
b Non-US region includes UK $i19,426
million.
c Includes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments.
6.iSales and other operating revenues
i
$ million
2020
2019
2018
Crude
oil
i5,048
i9,141
i10,331
Oil
products
i63,564
i102,408
i108,515
Natural
gas, LNG and NGLs
i12,726
i18,909
i20,494
Non-oil
products and other revenues from contracts with customers
a Principally
relates to physically settled derivative sales contracts.
An analysis of third-party sales and other operating revenues by segment and region is provided in Note 5.
The group’s sales to customers of crude oil and oil products were substantially all made by the Downstream segment. The group’s sales to customers of natural gas, LNG and NGLs were made by the Upstream segment. A significant majority of the group’s sales of non-oil products and other revenues from contracts with customers were made by the Downstream segment.
Amounts shown for revenue from contracts
with customers and other operating revenues for 2018 and 2019 have been represented to align with the current period. See Note 1 - Other changes to significant accounting policies - Physically settled derivative contracts for further information.
7.iIncome
statement analysis
i
$
million
2020
2019
2018
Interest and other income
Interest income from
Financial assets measured at amortized cost
i215
i371
i421
Financial
assets measured at fair value through profit or loss
i25
i49
i39
Other
income
i423
i349
i313
i663
i769
i773
Currency
exchange losses charged to the income statementa
i38
i37
i368
Expenditure
on research and development
i332
i364
i429
Costs
relating to the Gulf of Mexico oil spill (pre-interest and tax)b
i255
i319
i714
Finance
costs
Interest expense on lease liabilitiesc
i337
i379
i51
Interest
expense on other liabilities measured at amortized costd
i2,166
i2,410
i2,147
Capitalized
at i2.75% (2019 i3.50% and 2018 i3.56%)e
(i345)
(i374)
(i419)
Unwinding
of discount on provisionsf
i437
i505
i210
Unwinding
of discount on other payables measured at amortized cost
i520
i569
i539
i3,115
i3,489
i2,528
a Excludes
exchange gains and losses arising on financial instruments measured at fair value through profit or loss.
b Included within production and manufacturing expenses.
c Interest payable on lease liabilities in 2018 comparative period relates to leases previously classified as finance leases under IAS 17.
d 2020 includes a loss of $i158 million
associated with the buyback of finance debt.
e Tax relief on capitalized interest is approximately $i83 million (2019 $i51
million and 2018 $i55 million).
f From1 July 2018, the group changed its method of discounting and unwinding provisions from using real rates to using nominal rates.
/
bp
Annual Report and Form 20-F 2020
183
8.iExploration for and evaluation of oil and natural gas resources
The
following financial information represents the amounts included within the group totals relating to activity associated with the exploration for and evaluation of oil and natural gas resources. All such activity is recorded within the Upstream segment.
For information on significant judgements made in relation to oil and natural gas accounting see Intangible assets in Note 1.
i
$
million
2020
2019
2018
Exploration and evaluation costs
Exploration expenditure written offa
i9,920
i631
i1,085
Other
exploration costs
i360
i333
i360
Exploration
expense for the year
i10,280
i964
i1,445
Impairment
losses
i156
i2
i137
Intangible
assets – exploration and appraisal expenditureb c
i4,113
i14,091
i15,989
Liabilities
i71
i73
i60
Net
assets
i4,042
i14,018
i15,929
Cash
used in operating activities
i360
i333
i360
Cash
used in investing activities
i674
i1,215
i1,119
a
2020 includes $i2,643 million in the Gulf of Mexico primarily relating to the Paleogene assets, $i2,539
million in Canada primarily relating to Terre de Grace, $i2,141 million in Brazil, $i952 million
in Egypt and $i832 million in Angola. 2018 included $i447
million in the deepwater Gulf of Mexico principally relating to licence expiries. For further information see Upstream – Exploration on page .
b 2019 includes approximately $i2.5 billion relating to Canadian oil sands.
c Amount capitalized at 31 December 2020 relates to assets in various regions. The largest of these is $i0.7
billion capitalised in the Middle East region.
/
9.iTaxation
i
Tax
on profit
$ million
2020
2019
2018
Current tax
Charge
for the year
i2,095
i5,316
i6,217
Adjustment
in respect of prior yearsa
i50
(i68)
(i221)
i2,145
i5,248
i5,996
Deferred
taxb
Origination and reversal of temporary differences in the current year
(i7,826)
(i1,190)
i907
Adjustment
in respect of prior years
i1,522
(i94)
i242
(i6,304)
(i1,284)
i1,149
Tax
charge (credit) on profit or loss
(i4,159)
i3,964
i7,145
a The
adjustments in respect of prior years reflect the reassessment of the current tax balances for prior years in light of changes in facts and circumstances during the year.
b Origination and reversal of temporary differences in the current year include the impact of tax rate changes on deferred tax balances. The adjustments in respect of prior years reflect the reassessment of deferred tax balances for prior periods in light of all other changes in facts and circumstances during the year; 2020 includes charges for the reassessment of deferred tax asset recognition in light of revisions to price assumptions.
/
In 2020, the total tax charge recognized within other comprehensive income was $i39
million (2019 $i227 million charge and 2018 $i714
million charge), primarily comprising the deferred tax impact of the remeasurements of the net pension and other post-retirement benefit liability or asset. See Note 32 for further information.
The total tax charge recognized directly in equity was $i154 million (2019 $i37
million charge and 2018 $i17 million charge). 2020 principally relates to a non-controlling interest transaction entered into by Rosneft.
Reconciliation of the effective tax rate
The following table provides a reconciliation of the group weighted average statutory corporate income tax rate to the effective tax rate of the group on profit or loss before taxation.
184
bp
Annual Report and Form 20-F 2020
Financial statements
i
9.
Taxation – continued
$ million
2020
2019
2018
Profit (loss) before taxation
(i24,888)
i8,154
i16,723
Tax
charge (credit) on profit or loss
(i4,159)
i3,964
i7,145
Effective
tax rate
i17%
i49%
i43%
%
Tax
rate computed at the weighted average statutory ratea
i31
i52
i43
Increase
(decrease) resulting from
Tax reported in equity-accounted entities
i—
(i7)
(i5)
Adjustments
in respect of prior years
(i6)
(i2)
i—
Deferred
tax not recognized
(i3)
(i2)
i1
Tax
incentives for investment
i1
(i3)
(i2)
Foreign
exchange
(i1)
i1
i3
Items
not deductible for tax purposes
(i3)
i4
i1
Other
(i2)
i6
i2
Effective
tax rate
i17
i49
i43
a Calculated
based on the statutory corporate income tax rate applicable in the countries in which the group operates, weighted by the profits and losses before tax in the respective countries.
/
Deferred tax
i
$
million
Analysis of movements during the year in the net deferred tax (asset) liability
2020
2019
At 31 December
i5,190
i6,106
Adjustment
on adoption of IFRS 16
i—
(i75)
At
1 January
i5,190
i6,031
Exchange
adjustments
i55
i72
Credit
for the year in the income statement
(i6,304)
(i1,284)
Charge
for the year in other comprehensive income
i48
i233
Charge
for the year in equity
i154
i37
Acquisitions
and disposals
(i56)
i101
At
31 December
(i913)
i5,190
The
following table provides an analysis of deferred tax in the income statement and the balance sheet by category of temporary difference:
$ million
Income
statementa
Balance sheet
2020
2019
2018
2020
2019
Deferred tax liability
Depreciation
(i7,295)
(i1,436)
(i1,297)
i15,361
i22,627
Pension
plan surpluses
i69
(i31)
i65
i2,691
i2,290
Derivative
financial instruments
i33
i29
(i36)
i63
i29
Other
taxable temporary differences
(i32)
i159
(i57)
i1,562
i1,496
(i7,225)
(i1,279)
(i1,325)
i19,677
i26,442
Deferred
tax asset
Depreciation
(i849)
i—
i—
(i849)
i—
Lease
liabilities
i286
i264
i8
(i1,122)
(i1,380)
Pension
plan and other post-retirement benefit plan deficits
i2
i62
(i6)
(i1,548)
(i1,367)
Decommissioning,
environmental and other provisions
i438
(i472)
i1,505
(i7,155)
(i7,579)
Derivative
financial instruments
i—
i63
(i31)
(i25)
(i24)
Tax
credits
i310
(i336)
i123
(i3,652)
(i3,964)
Loss
carry forward
i543
i12
i559
(i5,319)
(i5,834)
Other
deductible temporary differences
i191
i402
i316
(i920)
(i1,104)
i921
(i5)
i2,474
(i20,590)
(i21,252)
Net
deferred tax charge (credit) and net deferred tax (asset) liabilityb
(i6,304)
(i1,284)
i1,149
(i913)
i5,190
Of
which – deferred tax liabilities
i6,831
i9,750
–
deferred tax assets
i7,744
i4,560
a The
2018 income statement is impacted by the reduction in US federal corporate income tax rate from 35% to 21%, effective from 1 January 2018.
b Included within the net deferred tax (asset) liability is a deferred tax asset balance of $i5,471 million (2019 $i5,526
million) related to the Gulf of Mexico oil spill.
/
bp Annual Report and Form 20-F 2020
185
9.
Taxation – continued
Of the $i7,744 million of deferred tax assets recognised on the group balance sheet at 31 December 2020 (2019 $i4,560 million), $i7,659
million (2019 $i2,421 million) relates to entities that have suffered a loss in either the current or preceding period. This amount is supported by forecasts that indicate sufficient future
taxable profits will be available to utilize such assets. For 2020, $i3,906 million relates to the US, $i707
million relates to India, $i637 million relates to Australia and $i588 million
relates to Trinidad & Tobago (2019 $i2,421 million relates to the US).
A summary of temporary differences, unused tax credits and unused tax
losses for which deferred tax has not been recognized is shown in the table below.
$ billion
At 31 December
2020
2019
Unused US state tax lossesa
i2.4
i2.3
Unused
tax losses – other jurisdictionsb
i6.0
i3.5
Unused
tax credits
i26.9
i25.4
of
which – arising in the UKc
i23.0
i21.5
–
arising in the USd
i3.9
i3.9
Deductible
temporary differencese
i46.1
i40.4
Taxable
temporary differences associated with investments in subsidiaries and equity-accounted entities
i0.8
i1.5
a For
2020 these losses expire in the period 2021-2040 with applicable tax rates ranging from i3% to i10%.
b The majority of the unused tax losses have no fixed expiry date.
c The
UK unused tax credits arise predominantly in overseas branches of UK entities based in jurisdictions with higher statutory corporate income tax rates than the UK. No deferred tax asset has been recognized on these tax credits as they are unlikely to have value in the future; UK taxes on these overseas branches are largely mitigated by double tax relief in respect of overseas tax. These tax credits have no fixed expiry date.
d For 2020 the US unused tax credits expire in the period 2021-2030.
e The majority comprises fixed asset temporary differences in the UK. Substantially all of the temporary differences have no expiry date.
i
$
million
Impact of previously unrecognized deferred tax or write-down of deferred tax assets on tax charge
2020
2019
2018
Current tax benefit relating to the utilization of previously unrecognized deferred tax assets
i46
i272
i83
Deferred
tax benefit arising from the reversal of a previous write-down of deferred tax assets
i11
i96
i—
Deferred
tax benefit relating to the recognition of previously unrecognized deferred tax assets
i—
i364
i112
Deferred
tax expense arising from the write-down of a previously recognized deferred tax asset
i1,622
i73
i169
/
10.iDividends
The quarterly dividend which is expected to be paid on 26 March 2021 in respect of the fourth quarter 2020 is i5.25
cents per ordinary share ($i0.315 per American Depositary Share (ADS)). The corresponding amount in sterling was announced on 15 March 2021.
i
Pence
per share
Cents per share
$ million
2020
2019
2018
2020
2019
2018
2020
2019
2018
Dividends announced and paid in cash
Preference
shares
i1
i1
i1
Ordinary
shares
March
i8.1558
i7.7382
i7.1691
i10.50
i10.25
i10.00
i2,102
i1,435
i1,828
June
i8.3421
i8.0655
i7.4435
i10.50
i10.25
i10.00
i2,119
i1,779
i1,727
September
i4.0433
i8.3475
i7.9296
i5.25
i10.25
i10.25
i1,059
i1,656
i1,409
December
i3.9169
i7.8250
i8.0251
i5.25
i10.25
i10.25
i1,059
i2,075
i1,734
i24.4581
i31.9762
i30.5673
i31.50
i41.00
i40.50
i6,340
i6,946
i6,699
Dividend
announced, paid in March 2021
i5.25
i1,067
/
The
amount of unclaimed dividends recognised as a liability at 31 December 2020 is $i50 million (2019 $i22 million).
The details of the scrip
dividends issued are shown in the table below. The board decided not to offer a scrip dividend alternative in respect of any dividends announced since the third quarter 2019, including the fourth quarter 2020 dividend expected to be paid on 26 March 2021.
2020
2019
2018
Number of shares issued (thousand)
i—
i208,927
i195,305
Value
of shares issued ($ million)
i—
i1,387
i1,381
The
financial statements for the year ended 31 December 2020 do not reflect the dividend announced on 2 February 2021 and paid in March 2021; this will be treated as an appropriation of profit in the year ending 31 December 2021.
186
bp Annual Report and Form 20-F 2020
Financial
statements
11.iEarnings per share
i
Cents
per share
Per ordinary share
2020
2019
2018
Basic earnings per share
(i100.42)
i19.84
i46.98
Diluted
earnings per share
(i100.42)
i19.73
i46.67
Dollars per share
Per
American Depositary Share (ADS)a
2020
2019
2018
Basic earnings per share
(i6.03)
i1.19
i2.82
Diluted
earnings per share
(i6.03)
i1.18
i2.80
/
aOne
ADS is equivalent to six ordinary shares.
Basic earnings per ordinary share amounts are calculated by dividing the profit for the year attributable to bp ordinary shareholders by the weighted average number of ordinary shares outstanding during the year.
The weighted average number of shares outstanding includes certain shares that will be issuable in the future under employee share-based payment plans and excludes treasury shares, which includes shares held by the Employee Share Ownership Plan trusts (ESOPs).
For the diluted earnings per share calculation, the weighted average number of shares outstanding during the year is adjusted for the average number of shares that are potentially issuable in connection with employee share-based payment plans. If the inclusion of potentially issuable shares would decrease loss per share, the potentially
issuable shares are excluded from the weighted average number of shares outstanding used to calculate diluted earnings per share.
$ million
2020
2019
2018
Profit
attributable to bp shareholders
(i20,305)
i4,026
i9,383
Less:
dividend requirements on preference shares
i1
i1
i1
Profit
for the year attributable to bp ordinary shareholders
(i20,306)
i4,025
i9,382
Shares
thousand
2020
2019
2018
Basic weighted average number of ordinary shares
i20,221,514
i20,284,859
i19,970,215
Potential
dilutive effect of ordinary shares issuable under employee share-based payment plans
i—
i114,811
i132,278
Weighted
average number of ordinary shares outstanding used to calculate diluted earnings per share
i20,221,514
i20,399,670
i20,102,493
Shares
thousand
2020
2019
2018
Basic weighted average number of ordinary shares – ADS equivalent
i3,370,252
i3,380,809
i3,328,369
Potential
dilutive effect of ordinary shares (ADS equivalent) issuable under employee share-based payment plans
i—
i19,136
i22,046
Weighted
average number of ordinary shares (ADS equivalent) outstanding used to calculate diluted earnings per share
i3,370,252
i3,399,945
i3,350,415
The
number of ordinary shares outstanding at 31 December 2020, excluding treasury shares, and including certain shares that will be issuable in the future under employee share-based payment plans was i20,264,027,711. Between 31 December 2020 and 25 February 2021, the latest practicable date before the completion of these financial statements, there was a net increase of i66,249,231
in the number of ordinary shares outstanding primarily as a result of share issues in relation to employee share-based payment plans.
Employee share-based payment plans
The group operates share and share option plans for directors and certain employees to obtain ordinary shares and ADSs in the company. Information on these plans for directors is shown in the Directors remuneration report on pages 103-126.
i
The
following table shows the number of shares potentially issuable under equity-settled employee share option plans, including the number of options outstanding, the number of options exercisable at the end of each year, and the corresponding weighted average exercise prices. The dilutive effect of these plans at 31 December is also shown.
Share options
2020
2019
Number
of optionsa b
thousand
Weighted average exercise price $
Number of optionsa b
thousand
Weighted average exercise price $
Outstanding
i28,171
i3.79
i17,112
i4.91
Exercisable
i1,874
i5.02
i1,067
i3.97
Dilutive
effect
i2,497
n/a
i3,990
n/a
a Numbers
of options shown are ordinary share equivalents (one ADS is equivalent to isix ordinary shares).
b At 31 December 2020 the quoted market price of one bp ordinary share was £i2.55
(2019 £i4.72).
/
In addition, the group operates a number of equity-settled employee share plans under which share units are granted to the group’s senior leaders and certain other employees. These plans typically have a ithree-year
performance or restricted period during which the units accrue net notional dividends which are treated as having been reinvested. Leaving employment will normally preclude the conversion of units into shares, but special arrangements apply for participants that leave for qualifying reasons. The number of shares that are expected to vest each year under employee share plans are shown in the table below. The dilutive effect of the employee share plans at 31 December is also shown.
bp
Annual Report and Form 20-F 2020
187
11.Earnings per share – continued
Share plans
2020
2019
Number
of sharesa
Number of sharesa
Vesting
thousand
thousand
Within one year
i87,517
i91,105
1
to 2 years
i85,720
i89,939
2
to 3 years
i147,097
i80,844
3
to 4 years
i749
i725
Over
4 years
i349
i576
i321,432
i263,189
Dilutive
effect
i104,068
i92,343
a Numbers
of shares shown are ordinary share equivalents (one ADS is equivalent to isix ordinary shares).
There has been a net decrease of i29,718,486
in the number of potential ordinary shares relating to employee share-based payment plans between 31 December 2020 and 25 February 2021.
188
bp Annual Report and Form 20-F 2020
Financial
statements
12.iProperty, plant and equipment (PP&E)
$
million
Land and land improvements
Buildings
Oil and gas propertiesa
Plant, machinery and equipment
Fittings, fixtures and office equipment
Transportation
Oil depots, storage tanks and service stations
Total
Cost - owned PP&E
At
1 January 2020
i3,609
i1,422
i214,352
i46,724
i2,532
i3,474
i8,694
i280,807
Exchange
adjustments
i219
i6
i—
i801
i33
i8
i603
i1,670
Additions
i101
i63
i6,922
i1,539
i586
i49
i864
i10,124
Acquisitions
i89
i—
i—
i35
i5
i9
i376
i514
Transfers
from intangible assets
i—
i—
i605
i—
i—
i—
i—
i605
Reclassified
as assets held for sale
i—
i—
(i1,425)
i—
i—
i—
i—
(i1,425)
Deletions
(i146)
(i281)
(i6,131)
(i6,185)
(i738)
(i491)
(i261)
(i14,233)
At
31 December 2020
i3,872
i1,210
i214,323
i42,914
i2,418
i3,049
i10,276
i278,062
Depreciation
- owned PP&E
At 1 January 2020
i581
i697
i124,766
i21,527
i2,006
i2,744
i4,865
i157,186
Exchange
adjustments
i35
i6
i—
i424
i26
i9
i379
i879
Charge
for the year
i113
i46
i10,068
i1,312
i170
i77
i740
i12,526
Impairment
losses
i8
i9
i11,705
i744
i2
i4
i3
i12,475
Impairment
reversals
i—
(i1)
(i83)
i—
i—
(i5)
i—
(i89)
Reclassified
as assets held for sale
i—
i—
(i326)
i—
i—
i—
i—
(i326)
Deletions
(i45)
(i126)
(i5,579)
(i3,976)
(i359)
(i448)
(i201)
(i10,734)
At
31 December 2020
i692
i631
i140,551
i20,031
i1,845
i2,381
i5,786
i171,917
Owned
PP&E - net book amount at 31 December 2020
i3,180
i579
i73,772
i22,883
i573
i668
i4,490
i106,145
Right-of-use
assets - net book amount at 31 December 2020b
i—
i1,254
i77
i792
i21
i2,855
i3,692
i8,691
Total
PP&E - net book amount at 31 December 2020
i3,180
i1,833
i73,849
i23,675
i594
i3,523
i8,182
i114,836
Cost
- owned PP&E
At 1 January 2019
i3,562
i1,502
i232,684
i45,721
i2,747
i10,183
i8,866
i305,265
Exchange
adjustments
(i22)
i5
i—
(i158)
i15
(i3)
(i69)
(i232)
Additions
i88
i93
i13,237
i2,433
i172
i274
i644
i16,941
Acquisitions
i51
i—
i—
i—
i—
i—
i8
i59
Transfers
from intangible assets
i—
i—
i1,885
i—
i—
i—
i—
i1,885
Reclassified
as assets held for sale
(i26)
i—
(i22,602)
i—
(i76)
(i6,708)
i—
(i29,412)
Deletions
(i44)
(i178)
(i10,852)
(i1,272)
(i326)
(i272)
(i755)
(i13,699)
At
31 December 2019
i3,609
i1,422
i214,352
i46,724
i2,532
i3,474
i8,694
i280,807
Depreciation
- owned PP&E
At 1 January 2019
i626
i697
i133,687
i20,512
i2,041
i7,819
i5,146
i170,528
Exchange
adjustments
(i4)
i5
i—
(i63)
i12
(i3)
(i45)
(i98)
Charge
for the year
i44
i59
i13,012
i1,705
i168
i173
i420
i15,581
Impairment
losses
i1
i1
i5,871
i64
i1
i404
i4
i6,346
Impairment
reversals
i—
i—
(i129)
i—
i—
(i2)
i—
(i131)
Reclassified
as assets held for sale
i—
i—
(i17,764)
i—
(i69)
(i5,478)
i—
(i23,311)
Deletions
(i86)
(i65)
(i9,911)
(i691)
(i147)
(i169)
(i660)
(i11,729)
At
31 December 2019
i581
i697
i124,766
i21,527
i2,006
i2,744
i4,865
i157,186
Owned
PP&E - net book amount at 31 December 2019
i3,028
i725
i89,586
i25,197
i526
i730
i3,829
i123,621
Right-of-use
assets - net book amount at 31 December 2019b
i—
i1,196
i128
i1,241
i16
i3,385
i3,055
i9,021
Total
PP&E - net book amount at 31 December 2019
i3,028
i1,921
i89,714
i26,438
i542
i4,115
i6,884
i132,642
Assets
under construction included above
At 31 December 2020
i17,259
At
31 December 2019
i23,897
Depreciation charge for the year on right-of-use assets
2020
i192
i43
i637
i10
i829
i579
i2,290
2019
i220
i31
i671
i9
i784
i526
i2,241
a
For information on significant estimates and judgements made in relation to the estimation of oil and natural reserves see Property, plant and equipment within Note 1.
b $i284 million (2019 $i653
million) of drilling rig right-of-use assets and $i2,521 million (2019 $i2,929 million) of shipping vessel right-of-use assets are included in Plant, machinery and equipment and
Transportation respectively.
bp Annual Report and Form 20-F 2020
189
13.iCapital
commitments
Authorized future capital expenditure for property, plant and equipment (excluding right-of-use assets) by group companies for which contracts had been signed at 31 December 2020 amounted to $i8,009 million (2019 $i11,382
million, 2018 $i8,319 million). bp has contracted capital commitments amounting to $i1,087 million (2019 $i77 million,
2018 $i25 million) in relation to joint ventures and $i183 million (2019 $i787
million, 2018 $i1,227 million) in relation to associates. bp’s share of contracted capital commitments of joint ventures amounted to $i900
million (2019 $i1,024 million, 2018 $i619 million).
14.iGoodwill and impairment review of goodwill
i
$
million
2020
2019
Cost
At 1 January
i12,865
i12,815
Exchange
adjustments
i184
i79
Acquisitions
and other additionsa
i632
i26
Reclassified
as assets held for sale
(i199)
i—
Deletions
(i389)
(i55)
At
31 December
i13,093
i12,865
Impairment
losses
At 1 January
i997
i611
Exchange
adjustments
i1
i—
Impairment
losses for the year
i1
i386
Deletions
(i386)
i—
At
31 December
i613
i997
Net
book amount at 31 December
i12,480
i11,868
Net
book amount at 1 January
i11,868
i12,204
a
2020 principally relates to an acquisition in the US Fuels business.
Impairment review of goodwill
$ million
Goodwill at 31 December
2020
2019
Upstream
i7,765
i7,958
Downstream
i4,660
i3,904
Other
businesses and corporate
i55
i6
i12,480
i11,868
/
Goodwill
acquired through business combinations has been allocated to groups of cash-generating units that are expected to benefit from the synergies of the acquisition. For Upstream, goodwill is allocated to all oil and gas assets in aggregate at the segment level. For Downstream, goodwill has been allocated to Lubricants, US Fuels, European Fuels and Other.
For information on significant estimates and judgements made in relation to impairments see Impairment of property, plant and equipment, intangible assets and goodwill in Note 1.
Upstream
i
$
million
2020
2019
Goodwill
i7,765
i7,958
Excess
of recoverable amount over carrying amount
i31,749
i93,250
/
The
table above shows the carrying amount of goodwill for the segment at the period end and the excess of the recoverable amount, based on a pre-tax value-in-use calculation, over the carrying amount (headroom) at the date of the most recent test. The reduction in headroom since the prior period principally relates to the impact of changes to price assumptions.
iNo impairment of the Upstream goodwill balance was recognized during 2020 (2019 $i386
million).
The value in use is based on the cash flows expected to be generated by the projected oil or natural gas production profiles up to the expected dates of cessation of production of each producing field, based on current estimates of reserves and resources, appropriately risked. Midstream and supply and trading activities and equity-accounted entities are generally not included in the impairment review of goodwill, as they do not represent part of the grouping of cash-generating units to which the goodwill relates and which is used to monitor the goodwill for internal management purposes. Where such activities form part of a wider Upstream cash-generating unit, they are reflected in the test. As the production profile and related cash flows can be estimated from bp’s past experience, management believes that the cash flows generated over the estimated life of field is the appropriate basis upon which to assess goodwill
and individual assets for impairment. The estimated date of cessation of production depends on the interaction of a number of variables, such as the recoverable quantities of hydrocarbons, the production profile of the hydrocarbons, the cost of the development of the infrastructure necessary to recover the hydrocarbons, production costs, the contractual duration of the production concession and the selling price of the hydrocarbons produced. As each producing field has specific reservoir characteristics and economic circumstances, the cash flows of each field is computed using appropriate individual economic models and key assumptions agreed by bp management.
Estimated production volumes and cash flows up to the date of cessation of production on a field-by-field basis, including operating and capital expenditure, are derived from the business segment plan. The production profiles used are consistent with the reserve and resource
volumes approved as part of bp’s centrally controlled process for the estimation of proved and probable reserves and total resources. Oil and gas price assumptions and discount rate assumptions used were as disclosed in Note 1. The average production for the purposes of goodwill impairment testing over the next i15 years is i877
mmboe per year (2019 i829 mmboe per year). The weighted average pre-tax discount rate used in the test is i11%
(2019 i12%).
190
bp Annual Report and
Form 20-F 2020
Financial statements
14.Goodwill and impairment review of goodwill – continued
The most recent review for impairment was carried out in the fourth quarter. The key assumptions used in the value-in-use calculation are oil and natural gas prices, production volumes and the discount rate. The value-in-use calculation has been prepared solely for the purposes of determining whether the goodwill balance was impaired. Estimated future cash flows were prepared on the basis of certain
assumptions prevailing at the time of the test. The actual outcomes may differ from the assumptions made. For example, reserves and resources estimates and production forecasts are subject to revision as further technical information becomes available and economic conditions change. Due to economic developments, regulatory change and emissions reduction activity arising from climate concern and other factors, future commodity prices and other assumptions may differ from the forecasts used in the calculations.
Sensitivities to different variables have been estimated using certain simplifying assumptions. For example, lower oil and gas price or production sensitivities do not fully reflect the specific impacts for each contractual arrangement and will not capture all favourable impacts that may arise from cost deflation or savings. A detailed calculation at any given price or production profile may, therefore, produce a different
result.
Adverse changes in input assumptions applied in respect to assets carried at or close to their value in use, primarily being those assets previously impaired, would have a limited effect on goodwill headroom, instead resulting in a direct impairment of the particular cash-generating unit's net book value. Conversely, a reduction in the value in use of those assets carried at a value below their respective values in use would result in an adverse impact on the goodwill headroom. It is estimated that a i21%
reduction in revenue throughout each year of the remaining life of those assets, either as a result of adverse price or production conditions or a combination of each, would cause the recoverable amount to be equal to the carrying amount of goodwill and related net non-current assets of the segment.
It is estimated that no reasonably possible change in the discount rate would cause the recoverable amount to be equal to the carrying amount of goodwill and related net non-current assets of the segment.
Downstream
$
million
2020
2019
Lubricants
US Fuels
European Fuels
Other
Total
Lubricants
US Fuels
European
Fuels
Other
Total
Goodwill
i2,865
i606
i913
i276
i4,660
i2,779
i—
i858
i267
i3,904
Cash
flows for each cash-generating unit are derived from the business segment plans, which cover a period of up to ifive years. To determine the value in use for each of the cash-generating units, cash flows for a period of i10
years are discounted and aggregated with a terminal value.
Lubricants
As permitted by IAS 36, the detailed calculations of Lubricants’ recoverable amount performed in the most recent detailed calculation in 2018 was used as the basis for the tests in 2020 as the criteria of IAS 36 were considered satisfied: the headroom was substantial in 2018; there have been no significant changes in the assets and liabilities; and the likelihood that the recoverable amount would be less than the carrying amount is remote.
The key assumptions to which the calculation of value in use for the Lubricants unit is most sensitive are operating unit margins, sales volumes, and discount rate. Operating margin and sales volumes assumptions used in the detailed impairment review of goodwill calculation are consistent with the assumptions used in the Lubricants
unit’s business plan and values assigned to these key assumptions reflect past experience. No reasonably possible change in any of these key assumptions would cause the unit’s carrying amount to exceed its recoverable amount. Cash flows beyond the plan period are extrapolated using a nominal i2.8% growth rate.
15.iIntangible assets
i
$
million
2020
2019
Exploration and appraisal expenditurea
Other intangibles
Total
Exploration and appraisal expenditurea
Other intangibles
Total
Cost
At
1 January
i15,306
i4,900
i20,206
i17,053
i4,504
i21,557
Exchange
adjustments
i—
i138
i138
i—
i2
i2
Acquisitions
i—
i318
i318
i—
i35
i35
Additions
i703
i645
i1,348
i1,268
i457
i1,725
Transfers
to property, plant and equipment
(i605)
i—
(i605)
(i1,885)
i—
(i1,885)
Reclassified
as assets held for sale
i—
i—
i—
(i671)
i—
(i671)
Deletions
(i987)
(i379)
(i1,366)
(i459)
(i98)
(i557)
At
31 December
i14,417
i5,622
i20,039
i15,306
i4,900
i20,206
Amortization
At
1 January
i1,215
i3,452
i4,667
i1,064
i3,209
i4,273
Exchange
adjustments
i—
i93
i93
i—
i4
i4
Exploration
expenditure written off
i9,920
i—
i9,920
i631
i—
i631
Charge
for the year
i—
i372
i372
i—
i331
i331
Impairment
losses
i156
i9
i165
i2
i2
i4
Reclassified
as assets held for sale
i—
i—
i—
(i61)
i—
(i61)
Deletions
(i987)
(i284)
(i1,271)
(i421)
(i94)
(i515)
At
31 December
i10,304
i3,642
i13,946
i1,215
i3,452
i4,667
Net
book amount at 31 December
i4,113
i1,980
i6,093
i14,091
i1,448
i15,539
Net
book amount at 1 January
i14,091
i1,448
i15,539
i15,989
i1,295
i17,284
a
For further information see Intangible assets within Note 1 and Note 8.
/
bp Annual Report and Form 20-F 2020
191
16.iInvestments in joint ventures
i
The
following table provides aggregated summarized financial information relating to the group’s share of joint ventures.
$ million
2020
2019a
2018
Sales
and other operating revenues
i10,545
i14,139
i13,258
Profit
before interest and taxation
(i151)
i976
i1,396
Finance
costs
i201
i109
i85
Profit
before taxation
(i352)
i867
i1,311
Taxation
(i51)
i289
i414
Non-controlling
interest
i1
i2
i—
Profit
for the year
(i302)
i576
i897
Other
comprehensive income
(i5)
(i6)
i6
Total
comprehensive income
(i307)
i570
i903
Non-current
assets
i12,646
i13,457
Current
assets
i3,424
i3,738
Total
assets
i16,070
i17,195
Current
liabilities
i2,644
i2,514
Non-current
liabilities
i5,023
i4,676
Total
liabilities
i7,667
i7,190
Net
assets
i8,403
i10,005
Less:
non-controlling interests
i39
i49
i8,364
i9,956
Group
investment in joint ventures
Group share of net assets (as above)
i8,364
i9,956
Loans
made by group companies to joint ventures
(i2)
i35
i8,362
i9,991
a 2019
has been restated to include non-controlling interest
/
i
Transactions between the group and its joint ventures are summarized below.
The
terms of the outstanding balances receivable from joint ventures are typically i30 to i45 days. The balances are unsecured and will be settled in cash. There are ino
significant provisions for doubtful debts relating to these balances and ino significant expense recognized in the income statement in respect of bad or doubtful debts. Dividends receivable are not included in the table above.
bp's share of impairment charges taken by joint ventures in 2020 was $i433
million (2019 $i25 million reversal) of which $i336
million (2019 $i25 million reversal) was in the Upstream segment.
17.iInvestments
in associates
i
The following table provides aggregated summarized financial information for the group’s associates as it relates to the amounts recognized in the group income statement and on the group balance sheet.
$
million
Income statement
Balance sheet
Earnings from associates - after interest and tax
Investments in associates
2020
2019
2018
2020
2019
Rosneft
(i229)
i2,295
i2,283
i11,808
i12,927
Other
associates
i128
i386
i573
i7,167
i7,407
(i101)
i2,681
i2,856
i18,975
i20,334
/
The
associate that is material to the group at both 31 December 2020 and 2019 is Rosneft.
192
bp Annual Report and Form 20-F 2020
Financial
statements
17. Investments in associates – continued
bp owns i19.75% of the voting shares of Rosneft which are listed on the MICEX stock exchange in Moscow and its global depository receipts are listed on the London Stock Exchange. Rosneft’s largest shareholder is Rosneftegaz JSC (Rosneftegaz), which is wholly owned by the Russian government. At 31 December 2020, Rosneftegaz held i40.4%
(2019 i50.0% plus ione share) of the voting shares of
Rosneft.
bp classifies its investment in Rosneft as an associate because, in management’s judgement, bp has significant influence over Rosneft; see Interests in other entities within Note 1 for further information. The group’s investment in Rosneft is a foreign operation whose functional currency is the Russian rouble. The decrease in the group's equity-accounted investment balance for Rosneft at 31 December 2020 compared with 31 December 2019 principally relates to adverse foreign exchange effects, which have been recognized in other comprehensive income, and dividends, partially offset by bp's share of Rosneft’s changes in equity.
During 2020 Rosneft completed a transaction to transfer all of its interest and cease participation in its Venezuelan businesses to a company owned by the government of the Russian Federation. In consideration, Rosneft received shares equal to a i9.6%
share of its own equity. The shares are held by a 100% subsidiary of Rosneft and accounted for as treasury shares. Rosneft also entered into share buyback transactions during the year. These are also accounted for as treasury shares. bp retains i19.75% of the voting rights at meetings of Rosneft shareholders and will continue to be entitled to dividends based on its current shareholding. bp’s economic interest, however, increased as a result of its indirect interest in the shares held by the subsidiary of Rosneft. bp’s share of profit or loss of Rosneft reflects
its economic interest. At 31 December 2020, bp's economic interest was i22.03%.
On 28 December 2020 Rosneft completed the acquisition of ii100/%
stakes in JSC Taimyrneftegaz and LLC Taimyrburservis, and the sale of a i10% interest in LLC Vostok Oil. A preliminary assessment of the fair values of the assets and liabilities acquired and the consideration transferred in respect of the acquisitions has been undertaken and the further impact, if any, on bp’s accounting for its equity-accounted investment in Rosneft will be updated once this has been finalised.
The value of bp’s i19.75%
shareholding in Rosneft based on the quoted market share price of $i5.64 per share (2019 $i7.21 per share) was $i11,804 million
at 31 December 2020 (2019 $i15,090 million). The value of bp's i22.03% economic interest
based on the quoted market share price was $i13,167 million at 31 December 2020.
The following table provides summarized financial information relating to Rosneft. This information is presented on a 100% basis and reflects adjustments made by bp to Rosneft’s own results in applying the equity method of accounting. bp adjusts Rosneft’s results for the accounting
required under IFRS relating to bp’s purchase of its interest in Rosneft and the amortization of the deferred gain relating to the disposal of bp’s interest in TNK-BP.
$ million
Gross amount
2020
2019
2018
Sales
and other operating revenues
i82,786
i134,046
i131,322
Profit
before interest and taxation
i1,270
i17,473
i18,886
Finance
costs
i1,742
i1,281
i2,785
Profit
(loss) before taxation
(i472)
i16,192
i16,101
Taxation
i208
i3,058
i2,957
Non-controlling
interests
i482
i1,514
i1,585
Profit
(loss) for the year
(i1,162)
i11,620
i11,559
Other
comprehensive income
i1,653
i572
i2,086
Total
comprehensive income
i491
i12,192
i13,645
Non-current
assets
i175,978
i161,327
Current
assets
i42,459
i38,657
Total
assets
i218,437
i199,984
Current
liabilities
i49,781
i44,459
Non-current
liabilities
i96,727
i79,327
Total
liabilities
i146,508
i123,786
Net
assets
i71,929
i76,198
Less:
non-controlling interests
i10,897
i10,744
i61,032
i65,454
The
group received dividends, net of withholding tax, of $i480 million from Rosneft in 2020 (2019 $i785 million and 2018 $i620
million).
i
bp
Annual Report and Form 20-F 2020
193
17. Investments in associates – continued
Summarized financial information for the group’s share of associates is shown below.
$
million
bp share
2020
2019
2018
Rosnefta
Other
Total
Rosnefta
Other
Total
Rosnefta
Other
Total
Sales and other operating revenues
i17,535
i5,946
i23,481
i26,474
i7,934
i34,408
i25,936
i9,134
i35,070
Profit
before interest and taxation
i295
i276
i571
i3,451
i788
i4,239
i3,730
i1,150
i4,880
Finance
costs
i372
i80
i452
i253
i87
i340
i550
i78
i628
Profit
(loss) before taxation
(i77)
i196
i119
i3,198
i701
i3,899
i3,180
i1,072
i4,252
Taxation
i51
i67
i118
i604
i315
i919
i584
i499
i1,083
Non-controlling
interests
i101
i1
i102
i299
i—
i299
i313
i—
i313
Profit
(loss) for the year
(i229)
i128
(i101)
i2,295
i386
i2,681
i2,283
i573
i2,856
Other
comprehensive income
i336
(i19)
i317
i113
(i25)
i88
i412
(i1)
i411
Total
comprehensive income
i107
i109
i216
i2,408
i361
i2,769
i2,695
i572
i3,267
Non-current
assets
i33,754
i11,449
i45,203
i31,862
i11,504
i43,366
Current
assets
i8,238
i1,749
i9,987
i7,635
i1,924
i9,559
Total
assets
i41,992
i13,198
i55,190
i39,497
i13,428
i52,925
Current
liabilities
i9,535
i1,346
i10,881
i8,781
i1,908
i10,689
Non-current
liabilities
i18,558
i4,709
i23,267
i15,667
i4,577
i20,244
Total
liabilities
i28,093
i6,055
i34,148
i24,448
i6,485
i30,933
Net
assets
i13,899
i7,143
i21,042
i15,049
i6,943
i21,992
Less:
non-controlling interests
i2,091
i—
i2,091
i2,122
i—
i2,122
i11,808
i7,143
i18,951
i12,927
i6,943
i19,870
Group
investment in associates
Group share of net assets (as above)
i11,808
i7,143
i18,951
i12,927
i6,943
i19,870
Loans
made by group companies to associates
i—
i24
i24
i—
i464
i464
i11,808
i7,167
i18,975
i12,927
i7,407
i20,334
a In
2014-2019, Rosneft adopted hedge accounting in relation to a portion of highly probable future export revenue denominated in US dollars. Foreign exchange gains and losses arising on the retranslation of borrowings denominated in currencies other than the Russian rouble and designated as hedging instruments were recognized initially in other comprehensive income, and were reclassified to the income statement as the hedged revenue was recognized.
During the year, bp and Reliance Industries completed the formation of a new fuels and mobility venture, Reliance BP Mobility Limited, that will operate across India under the Jio-bp brand. bp invested $i1
billion to acquire a i49% stake in the company.
Transactions between the group and its associates are summarized below.
$
million
Sales to associates
2020
2019
2018
Product
Sales
Amount receivable at 31 December
Sales
Amount receivable at 31 December
Sales
Amount receivable at 31 December
LNG,
crude oil and oil products, natural gas
i855
i169
i1,544
i243
i2,064
i393
$
million
Purchases from associates
2020
2019
2018
Product
Purchases
Amount payable at 31 December
Purchases
Amount payable at 31 December
Purchases
Amount payable at 31 December
Crude
oil and oil products, natural gas, transportation tariff
i4,926
i1,280
i9,503
i1,641
i14,112
i2,069
In
addition to the transactions shown in the table above, in 2018 bp acquired a i49% stake in LLC Kharampurneftegaz, a Rosneft subsidiary, which develops resources within the Kharampurskoe and Festivalnoye licence areas in Yamalo-Nenets in northern Russia. bp’s interest in LLC Kharampurneftegaz is accounted for as an associate.
The terms of the outstanding balances receivable from associates are typically i30
to i45 days. The balances are unsecured and will be settled in cash. There are ino significant
provisions for doubtful debts relating to these balances and ino significant expense recognized in the income statement in respect of bad or doubtful debts. Dividends receivable are not included in the table above.
The majority of purchases from associates relate to crude oil and oil products transactions with Rosneft. Sales to associates are related to various entities.
bp
has commitments amounting to $i10,777 million (2019 $i11,198
million), primarily in relation to contracts with its associates for the purchase of transportation capacity. For information on capital commitments in relation to associates see Note 13.
bp's share of impairment charges taken by associates in 2020 was $i414 million (2019 $i152 million).
194
bp
Annual Report and Form 20-F 2020
Financial statements
18.iOther
investments
i
$ million
2020
2019
Current
Non-current
Current
Non-current
Equity investmentsa
i—
i913
i—
i571
Contingent
consideration
i317
i1,682
i122
i476
Other
i16
i151
i47
i229
i333
i2,746
i169
i1,276
a Approximately
half of the group's equity investments are unlisted.
/
Contingent consideration relates to amounts arising on disposals which are financial assets classified as measured at fair value through profit or loss. The fair value is determined using an estimate of discounted future cash flows that are expected to be received and is considered a level 3 valuation under the fair value hierarchy. Future cash flows are estimated based on inputs including oil and natural gas prices, production volumes and operating costs related to the disposed operations. The discount rate used is based on a risk-free rate adjusted for asset-specific risks. The contingent consideration principally relates to the disposal of our Alaskan business.
19.iInventories
i
$
million
2020
2019
Crude oil
i4,498
i5,610
Natural
gas
i265
i222
Emissions
allowancesa
i1,297
i1,193
Refined
petroleum and petrochemical products
i8,791
i11,714
i14,851
i18,739
Trading
inventories
i292
i182
i15,143
i18,921
Supplies
i1,730
i1,959
i16,873
i20,880
Cost
of inventories expensed in the income statement
i132,104
i209,672
/
a
Comparative period has been re-presented to align with the current period.
The inventory valuation at 31 December 2020 is stated net of a provision of $i584 million (2019 $i650
million) to write down inventories to their net realizable value, of which $i216 million (2019 $i290 million) relates to hydrocarbon inventories. The net credit to the income statement in the year in respect
of inventory net realizable value provisions was $i17 million (2019 $i348 million credit), of which $i71
million credit (2019 $i309 million credit) related to hydrocarbon inventories.
Trading inventories are valued using quoted benchmark prices adjusted as appropriate for location and quality differentials. They are predominantly categorized within level 2 of the fair value hierarchy.
20.iTrade and other receivables
i
$
million
2020
2019
Current
Non-current
Current
Non-current
Financial assets
Trade receivables
i12,926
i19
i19,424
i22
Amounts
receivable from joint ventures and associates
i339
i10
i672
i2
Receivables
related to disposalsa
i1,291
i2,402
i159
i125
Other
receivables
i2,628
i637
i3,166
i701
i17,184
i3,068
i23,421
i850
Non-financial
assets
Gulf of Mexico oil spill trust fund reimbursement asset
i32
i—
i201
i—
Sales
taxes and production taxes
i557
i504
i640
i538
Other
receivables
i175
i779
i180
i759
i764
i1,283
i1,021
i1,297
i17,948
i4,351
i24,442
i2,147
/
a
For further information see Note 4 - Disposals and Impairment.
In both 2020 and 2019 the group entered into non-recourse arrangements to discount certain receivables in support of supply and trading activities and the management of credit risk.
Trade and other receivables, other than certain receivables related to disposals, are predominantly non-interest bearing. See Note 29 for further information.
bp
Annual Report and Form 20-F 2020
195
21.iValuation and qualifying accounts
i
$
million
2020
2019
2018
Trade and other receivables
Fixed asset investments
Trade and other receivables
Fixed asset investments
Trade and other receivables
Fixed asset investments
At 1 January – IAS 39
i509
i249
i416
i235
i335
i314
Adjustment
on adoption of IFRS 9
—
—
—
—
i115
(i85)
At
1 January – IFRS 9
i509
i249
i416
i235
i450
i229
Charged
to costs and expenses
i214
i103
i206
i28
i30
i10
Charged
to other accountsa
i2
i—
(i2)
i—
(i12)
(i1)
Deductions
(i170)
(i166)
(i111)
(i14)
(i52)
(i3)
At
31 December
i555
i186
i509
i249
i416
i235
a
Principally exchange adjustments.
/
Valuation and qualifying accounts relating to trade and other receivables comprise expected credit loss allowances. The adjustment on adoption of IFRS 9 relates to the additional loss allowance required by IFRS 9's expected credit loss model. The expected credit loss allowance comprises $i456 million (2019
$i414 million, 2018 $i327 million) relating to receivables that were credit-impaired at the end of the year and $i99
million (2019 $i95 million, 2018 $i89 million) relating to receivables that were not credit-impaired at the
end of the year. Whilst credit risk has increased since 31 December 2019, there has also been a significant reduction in the group's trade and other receivables balance. Therefore, the total expected credit loss allowances recognized as at 31 December 2020 have not significantly increased during the year.
Valuation and qualifying accounts relating to fixed asset investments comprise impairment provisions for investments in equity-accounted entities. The adjustment on adoption of IFRS 9 primarily relates to amounts provided against investments in equity instruments that were held at cost less impairment losses under IAS 39 but that are classified as measured at fair value through profit or loss under IFRS 9.
In addition to the amounts presented above, expected loss allowances on cash and cash equivalents classified as measured at amortized cost totalled $i11
million (2019 $i11 million). For further information on the group's credit risk management policies and how the group recognizes and measures expected losses see Note 29.
Valuation and qualifying accounts are deducted in the balance sheet from the assets to which they apply.
22.iTrade and other payables
i
$
million
2020
2019
Current
Non-current
Current
Non-current
Financial liabilities
Trade payables
i23,157
i—
i30,538
i—
Amounts
payable to joint ventures and associates
i1,364
i—
i1,866
i—
Payables
for capital expenditure and acquisitions
i2,297
i1,033
i3,868
i1,196
Payables
related to the Gulf of Mexico oil spill
i1,399
i9,988
i1,617
i10,863
Other
payables
i5,041
i681
i5,810
i133
i33,258
i11,702
i43,699
i12,192
Non-financial
liabilities
Sales taxes, customs duties, production taxes and social security
i2,103
i73
i2,381
i33
Other
payables
i653
i337
i749
i401
i2,756
i410
i3,130
i434
i36,014
i12,112
i46,829
i12,626
/
Materially
all of bp's trade payables have payment terms in the range of 30 to 60 days and give rise to operating cash flows.
Trade and other payables, other than those relating to the Gulf of Mexico oil spill, are predominantly interest free. See Note 29 (c) for further information.
Payables related to the Gulf of Mexico oil spill include amounts payable under the 2016 consent decree and settlement agreement with the United States and ifive
Gulf coast states, including amounts payable for natural resource damages, state claims and Clean Water Act penalties. On a discounted basis the amounts included in payables related to the Gulf of Mexico oil spill for these elements of the agreements are $i4,837 million payable over 12 years, $i2,584
million payable over 13 years and $i3,549 million payable over 12 years respectively at 31 December 2020. Reported within net cash provided by operating activities in the group cash flow statement is a net cash outflow of $i1,786
million (2019 outflow of $i2,694 million, 2018 outflow of $i3,531
million) related to the Gulf of Mexico oil spill, which includes payments made in relation to these agreements. For 2018 payments under the 2012 agreement with the US government to resolve all federal criminal claims arising from the incident are also included. For full details of these agreements, see bp Annual Report and Form 20-F 2015 - Legal Proceedings.
Payables related to the Gulf of Mexico oil spill at 31 December 2020 also include amounts payable for settled economic loss and property damage claims which are payable over a period of up to seven years.
196
bp
Annual Report and Form 20-F 2020
Financial statements
23.iProvisions
i
$
million
Decommissioning
Environmental
Litigation and claims
Emissions
Other
Total
At 1 January 2020
i15,110
i1,620
i1,281
i919
i2,021
i20,951
Exchange
adjustments
i96
i9
i1
i25
i84
i215
Increase
(decrease) in existing provisions
(i686)
i297
i260
i1,429
i974
i2,274
Write-back
of unused provisions
(i11)
(i88)
(i12)
(i17)
(i341)
(i469)
Unwinding
of discount
i369
i39
i18
i—
i11
i437
Utilization
(i7)
(i246)
(i508)
(i687)
(i378)
(i1,826)
Reclassified
to other payables
(i245)
i—
(i129)
i—
(i86)
(i460)
Reclassified
as liabilities directly associated with assets held for sale
(i10)
i—
i—
i—
i—
(i10)
Deletions
(i140)
(i2)
(i1)
i—
(i8)
(i151)
At
31 December 2020
i14,476
i1,629
i910
i1,669
i2,277
i20,961
Of
which – current
i428
i273
i260
i1,621
i1,179
i3,761
–
non-current
i14,048
i1,356
i650
i48
i1,098
i17,200
/
The
decommissioning provision comprises the future cost of decommissioning oil and natural gas wells, facilities and related pipelines. The environmental provision includes provisions for costs related to the control, abatement, clean-up or elimination of environmental pollution relating to soil, groundwater, surface water and sediment contamination. The litigation and claims category includes provisions for matters related to, for example, commercial disputes, product liability, and allegations of exposures of third parties to toxic substances. The emissions provision relates to the group’s obligation to transfer emissions allowances under relevant regulations. The provision will principally be settled through allowances already held as inventory in the group balance sheet.Included within the other category at 31 December 2020 are reinvent bp restructuring provisions for employee termination payments of $i428
million.
For information on significant estimates and judgements made in relation to provisions, see Provisions and contingencies within Note 1.
Gulf of Mexico oil spill
The group has recognized certain assets, payables and provisions and incurs certain residual costs relating to the Gulf of Mexico oil spill that occurred in 2010. In addition to the Litigation and claims narrative provided in this note, for further information see Notes 7, 9, 20, 22, 29, 33.
Litigation and claims
The Economic and Property Damages Settlement Agreement (EPD Settlement Agreement) with the Plaintiff's Steering Committee (PSC) provides for a court-supervised settlement programme, the Deepwater Horizon Court Supervised Settlement Programme (DHCSSP), which commenced operation
on 4 June 2012. On 22 January 2021, the United States District Court for the Eastern District of Louisiana issued an order determining the completion of all claims processing operations of the DHCSSP. The Court also concluded that future issues concerning EPD Settlement Agreement claims would be time barred under the DHCSSP and the claim administrator would proceed to complete post-closure administrative wind down activities. Amounts payable for settled economic and property damage claims are reported within payables - see Note 22 for further information.
A separate claims administrator was appointed to pay medical claims and to implement other aspects of the Medical Benefits Class Action Settlement. For further information on the PSC settlements, see Legal proceedings on page 226.
The litigation and claims provision reflects the latest estimate for the remaining costs associated
with the Gulf of Mexico oil spill. The amounts payable may differ from the amount provided and the timing of payments is uncertain.
24.iPensions and other post-retirement benefits
Most group companies have pension plans, the forms and benefits of which vary with conditions and practices
in the countries concerned. Pension benefits may be provided through defined contribution plans (money purchase schemes) or defined benefit plans (final salary and other types of schemes with committed pension benefit payments). For defined contribution plans, retirement benefits are determined by the value of funds arising from contributions paid in respect of each employee. For defined benefit plans, retirement benefits are based on such factors as an employee’s pensionable salary and length of service. Defined benefit plans may be funded or unfunded. The assets of funded plans are generally held in separately administered trusts.
For information on significant estimates and judgements made in relation to accounting for these plans see Pensions and other post-retirement benefits in Note 1.
The primary pension arrangement in the UK is a funded final salary pension plan under which
retired employees draw the majority of their benefit as an annuity. This pension plan is governed by a corporate trustee whose board is composed of ifour member-nominated directors, ifour
company-nominated directors, ione independent director and ione
independent chairman nominated by the company. The trustee board is required by law to act in the best interests of the plan participants and is responsible for setting certain policies, such as investment policies of the plan. The UK plan is closed to new joiners and is currently under consultation for closure to future accrual. As at 31 December 2020, it remained open to ongoing accrual for current members. New joiners in the UK are eligible for membership of a defined contribution plan.
In the US, all pension benefits now accrue under a cash balance formula. Benefits previously accrued under final salary formulas are legally protected. Retiring US employees typically take their pension benefit in the form of a lump sum payment upon retirement. The plan is funded and its assets are overseen by a fiduciary Investment Committee. During 2020
the committee was composed of iseven bp employees appointed by the president of bp Corporation North America Inc. (the appointing officer). The Investment Committee is required by law to act in the best interests of the plan participants and is responsible for setting certain policies, such as the investment policies of the plan. US employees are also eligible to participate in a defined contribution (401k) plan in which employee contributions
are matched with company contributions. In the US, group companies also provide post-retirement healthcare to most retired employees and their dependants (and, in certain cases, life insurance coverage); the entitlement to these benefits is usually based on the employee remaining in service until a specified age and completion of a minimum period of service.
bp Annual Report and Form 20-F 2020
197
24.
Pensions and other post-retirement benefits – continued
In the Eurozone, there are defined benefit pension plans in Germany, France, the Netherlands and other countries. In Germany and France, the majority of the pensions are unfunded, in line with market practice. In Germany, the group’s largest Eurozone plan, employees receive a pension and also have a choice to supplement their core pension through salary sacrifice. For employees who joined since 2002, the core pension benefit is a career average plan with retirement benefits based on such factors as an employee’s pensionable salary and length of service. The returns on the notional contributions made by both the company and employees are based on the interest rate which is set out in German tax law. Retired German employees take their pension benefit typically in the form of an annuity.
The German plans are governed by legal agreements between bp and the works council or between bp and the trade union.
The level of contributions to funded defined benefit plans is the amount needed to provide adequate funds to meet pension obligations as they fall due. During 2020 the aggregate level of contributions was $i325 million (2019 $i349
million and 2018 $i610 million). The aggregate level of contributions in 2021 is expected to be approximately $i400
million, and includes contributions in all countries that we expect to be required to make contributions by law or under contractual agreements, as well as an allowance for discretionary funding.
For the primary UK plan there is a funding agreement between the group and the trustee. On an annual basis a schedule of contributions is agreed covering the next ifive years. Contractually committed funding amounted to $i1,014
million at 31 December 2020, all of which relates to future service. This amount is included in the group’s committed cash flows relating to pensions and other post-retirement benefit plans as set out in the table of contractual obligations on page 307.
The surplus relating to the primary UK pension plan is recognized on the balance sheet on the basis that the company is entitled to a refund of any remaining assets once all members have left the plan.
Minimum pension funding in the US is determined by legislation and is supplemented by discretionary contributions. No contributions were made into the primary US pension plan in 2020 and no statutory funding requirement is expected in the next 12 months.
The surplus relating to the primary US fund is recognized
on the balance sheet on the basis that economic benefit can be gained from the surplus through a reduction in future contributions.
There was no minimum funding requirement for the US plan, and no significant minimum funding requirements in other countries at 31 December 2020.
The obligation and cost of providing pensions and other post-retirement benefits is assessed annually using the projected unit credit method. The date of the most recent actuarial review was 31 December 2020. The UK plans are subject to a formal actuarial valuation every three years; valuations are required more frequently in many other countries.The most recent formal actuarial valuation of the UK pension plans was as at 31 December 2017, and a valuation as at 31 December 2020 is currently underway. A valuation of the US plan and largest Eurozone plans are carried out annually.
The
material financial assumptions used to estimate the benefit obligations of the various plans are set out below. iThe assumptions are reviewed by management at the end of each year and are used to evaluate the accrued benefit obligation at 31 December and pension expense for the following year.
%
Financial
assumptions used to determine benefit obligation
UK
US
Eurozone
2020
2019
2018
2020
2019
2018
2020
2019
2018
Discount
rate for plan liabilities
i1.4
i2.1
i2.9
i2.2
i3.1
i4.1
i1.0
i1.3
i2.0
Rate
of increase in salaries
i3.6
i3.4
i3.8
i4.1
i3.9
i3.9
i2.9
i3.1
i3.1
Rate
of increase for pensions in payment
i2.8
i2.7
i3.0
i—
i—
i—
i1.3
i1.5
i1.5
Rate
of increase in deferred pensions
i2.8
i2.7
i3.0
i—
i—
i—
i0.5
i0.5
i0.5
Inflation
for plan liabilities
i2.9
i2.7
i3.1
i1.7
i1.5
i1.5
i1.5
i1.7
i1.7
%
Financial
assumptions used to determine benefit expense
UK
US
Eurozone
2020
2019
2018
2020
2019
2018
2020
2019
2018
Discount
rate for plan service cost
i2.1
i3.0
i2.6
i3.2
i4.2
i3.6
i1.8
i2.5
i2.4
Discount
rate for plan other finance expense
i2.1
i2.9
i2.5
i3.1
i4.1
i3.5
i1.3
i2.0
i1.9
Inflation
for plan service cost
i2.6
i3.1
i3.1
i1.5
i1.5
i1.7
i1.7
i1.7
i1.6
The
discount rate assumptions are based on third-party AA corporate bond indices and for our largest plans in the UK, US and the Eurozone we use yields that reflect the maturity profile of the expected benefit payments. The inflation rate assumptions for our UK and US plans are based on the difference between the yields on index-linked and fixed-interest long-term government bonds. In other countries, including the Eurozone, we use this approach, or advice from the local actuary depending on the information available. The inflation assumptions are used to determine the rate of increase for pensions in payment and the rate of increase in deferred pensions where there is such an increase.
The assumptions for the rate of increase in salaries are based on the inflation assumption plus an allowance for expected long-term real salary growth. These include an allowance for promotion-related salary growth, of up to i0.8%
depending on country.
198
bp Annual Report and Form 20-F 2020
Financial statements
24.
Pensions and other post-retirement benefits – continued
In addition to the financial assumptions, we regularly review the demographic and mortality assumptions. The mortality assumptions reflect best practice in the countries in which we provide pensions and have been chosen with regard to applicable published tables adjusted where appropriate to reflect the experience of the group and an extrapolation of past longevity improvements into the future. bp’s most substantial pension liabilities are in the UK, the US and the Eurozone where our mortality assumptions are as follows:
Years
Mortality
assumptions
UK
US
Eurozone
2020
2019
2018
2020
2019
2018
2020
2019
2018
Life
expectancy at age 60 for a male currently aged 60
i26.9
i27.3
i27.4
i24.7
i24.9
i25.1
i25.7
i25.7
i25.6
Life
expectancy at age 60 for a male currently aged 40
i28.4
i28.9
i28.9
i26.4
i26.7
i26.9
i28.2
i28.3
i28.1
Life
expectancy at age 60 for a female currently aged 60
i28.8
i28.7
i28.8
i27.7
i28.0
i28.5
i29.0
i29.1
i29.0
Life
expectancy at age 60 for a female currently aged 40
i30.4
i30.5
i30.6
i29.2
i29.7
i30.1
i31.2
i31.2
i31.2
Pension
plan assets are generally held in trusts, the primary objective of which is to accumulate assets sufficient to meet the obligations of the plans. The assets of the trusts are invested in a manner consistent with fiduciary obligations and principles that reflect current practices in portfolio management.
A significant proportion of the assets are held in equities, which are expected to generate a higher level of return over the long term, with an acceptable level of risk. In order to provide reasonable assurance that no single security or type of security has an unwarranted impact on the total portfolio, the investment portfolios are highly diversified.
The trustee’s long-term investment objective for the primary UK plan as it matures is to invest in assets whose value changes in the same way as the plan liabilities, in order to reduce the level of funding risk. To move towards this
objective, the UK plan uses a liability driven investment (LDI) approach for part of the portfolio, investing primarily in government bonds to achieve this matching effect for the most significant plan liability assumptions of interest rate and inflation rate. This is partly funded by short-term sale and repurchase agreements, whereby the plan borrows money using existing bonds as security and which will be bought back at a specified price at an agreed future date. The funds raised are used to invest in further bonds to increase the proportion of assets which match the plan liabilities. The borrowings are shown separately in the analysis of pension plan assets in the table below.
For the primary UK pension plan there is an agreement with the trustee to increase the proportion of assets with liability matching characteristics over time primarily by reducing the proportion of plan assets held as equities and increasing the proportion
held as bonds. During 2020, the UK plan switched i11% of plan assets from equities to bonds (2019 i2%).
There is a similar agreement in place for the primary US plan, although no switches have taken place in 2019 or 2020.
i
The current asset allocation policy for the major plans at 31 December 2020 was as follows:
UK
US
Asset
category
%
%
Total equity (including private equity)
i17
i40
Bonds/cash
(including LDI)
i76
i60
Property/real
estate
i7
i—
/
The
amounts invested under the LDI programme by the primary UK pension plan as at 31 December 2020 were $i4,217 million (2019 $i4,804
million) of government-issued nominal bonds and $i24,576 million (2019 $i19,462 million) of index-linked
bonds.
Some of the group’s pension plans in the Eurozone and other countries use derivative financial instruments as part of their asset mix to manage the level of risk. The fair value of these instruments is included in other assets in the table below.
The group’s main pension plans do not invest directly in either securities or property/real estate of the company or of any subsidiary.
The fair values of the various categories of assets held by the defined benefit plans at 31 December are presented in the table below, including the effects of derivative financial instruments. Movements in the fair value of plan assets during the year are shown in detail in the table on page 201.
bp
Annual Report and Form 20-F 2020
199
24. Pensions and other post-retirement benefits – continued
$
million
UKa
USb
Eurozone
Other
Total
Fair value of pension plan assets
At 31 December 2020
Listed
equities – developed markets
i5,008
i1,112
i542
i318
i6,980
–
emerging markets
i418
i115
i68
i70
i671
Private
equityc
i2,899
i1,604
i—
i4
i4,507
Government
issued nominal bondsd
i4,303
i1,839
i1,111
i616
i7,869
Government
issued index-linked bondsd
i24,576
i—
i107
i—
i24,683
Corporate
bondsd
i8,906
i2,398
i587
i279
i12,170
Propertye
i2,553
i—
i110
i28
i2,691
Cash
i1,392
i267
i51
i163
i1,873
Other
i795
i131
i104
i30
i1,060
Debt
(repurchase agreements) used to fund liability driven investments
(i9,387)
i—
i—
i—
(i9,387)
i41,463
i7,466
i2,680
i1,508
i53,117
At
31 December 2019
Listed equities – developed markets
i6,285
i1,290
i495
i371
i8,441
– emerging markets
i1,096
i124
i61
i64
i1,345
Private
equityc
i2,675
i1,474
i—
i3
i4,152
Government
issued nominal bondsd
i4,884
i2,100
i959
i572
i8,515
Government
issued index-linked bondsd
i19,462
i—
i100
i—
i19,562
Corporate
bondsd
i6,132
i2,304
i569
i256
i9,261
Propertye
i2,507
i—
i96
i27
i2,630
Cash
i426
i289
i33
i93
i841
Other
i98
i74
i30
i26
i228
Debt
(repurchase agreements) used to fund liability driven investments
(i7,436)
i—
i—
i—
(i7,436)
i36,129
i7,655
i2,343
i1,412
i47,539
At
31 December 2018
Listed equities – developed markets
i5,191
i1,238
i413
i306
i7,148
– emerging markets
i950
i63
i65
i56
i1,134
Private
equityc
i2,792
i1,495
i—
i4
i4,291
Government
issued nominal bondsd
i4,263
i2,072
i895
i533
i7,763
Government
issued index-linked bondsd
i17,491
i—
i102
i—
i17,593
Corporate
bondsd
i4,606
i2,184
i506
i243
i7,539
Propertye
i2,311
i6
i57
i25
i2,399
Cash
i376
i73
i42
i83
i574
Other
i116
i64
i32
i40
i252
Debt
(repurchase agreements) used to fund liability driven investments
(i6,011)
i—
i—
i—
(i6,011)
i32,085
i7,195
i2,112
i1,290
i42,682
a Bonds
held by the UK pension plans are denominated in sterling. Property held by the UK pension plans is in the United Kingdom.
b Bonds held by the US pension plans are denominated in US dollars.
c Private equity is valued at fair value based on the most recent transaction price or third-party net asset, revenue or earnings based valuations that generally result in the use of significant unobservable inputs.
d Bonds held by pension plans are valued using quoted prices in active markets.
e Properties are valued based on an analysis of recent market transactions supported by market knowledge derived from third-party professional valuers that generally result in the use of significant unobservable inputs.
200
bp
Annual Report and Form 20-F 2020
Financial statements
24. Pensions and other post-retirement benefits – continued
i
$
million
2020
UK
US
Eurozone
Other
Total
Analysis of the amount charged to profit or loss
Current
service costa
i250
i292
i103
i38
i683
Past
service costb
(i48)
(i66)
i12
(i20)
(i122)
Settlementb
i—
(i23)
i10
(i1)
(i14)
Operating
charge relating to defined benefit plans
i202
i203
i125
i17
i547
Payments
to defined contribution plans
i49
i183
i2
i38
i272
Total
operating charge
i251
i386
i127
i55
i819
Interest
income on plan assetsa
(i725)
(i210)
(i33)
(i40)
(i1,008)
Interest
on plan liabilities
i596
i289
i97
i59
i1,041
Other
finance (income) expense
(i129)
i79
i64
i19
i33
Analysis
of the amount recognized in other comprehensive income
Actual asset return less interest income on plan assets
i4,108
i1,041
i104
i38
i5,291
Change
in financial assumptions underlying the present value of the plan liabilities
(i4,207)
(i1,178)
(i143)
(i42)
(i5,570)
Change
in demographic assumptions underlying the present value of the plan liabilities
i585
i29
i56
(i4)
i666
Experience
gains and losses arising on the plan liabilities
i54
(i101)
(i178)
i8
(i217)
Remeasurements
recognized in other comprehensive income
i540
(i209)
(i161)
i—
i170
Movements
in benefit obligation during the year
Benefit obligation at 1 January
i29,780
i10,119
i7,353
i1,826
i49,078
Exchange
adjustments
i1,303
i—
i720
i64
i2,087
Operating
charge relating to defined benefit plans
i202
i203
i125
i17
i547
Interest
cost
i596
i289
i97
i59
i1,041
Contributions
by plan participantsc
i21
i—
i2
i11
i34
Benefit
payments (funded plans)d
(i1,291)
(i1,441)
(i81)
(i86)
(i2,899)
Benefit
payments (unfunded plans)d
(i8)
(i197)
(i265)
(i34)
(i504)
Reclassified
as assets held for sale
i—
(i1)
(i55)
i—
(i56)
Disposals
i—
(i35)
i—
i—
(i35)
Remeasurements
i3,568
i1,250
i265
i38
i5,121
Benefit
obligation at 31 Decembera e
i34,171
i10,187
i8,161
i1,895
i54,414
Movements
in fair value of plan assets during the year
Fair value of plan assets at 1 January
i36,129
i7,655
i2,343
i1,412
i47,539
Exchange
adjustments
i1,582
i—
i235
i64
i1,881
Interest
income on plan assetsaf
i725
i210
i33
i40
i1,008
Contributions
by plan participantsc
i21
i—
i2
i11
i34
Contributions
by employers (funded plans)
i189
i8
i99
i29
i325
Benefit
payments (funded plans)d
(i1,291)
(i1,441)
(i81)
(i86)
(i2,899)
Reclassified
as assets held for sale
i—
(i7)
(i55)
i—
(i62)
Remeasurementsf
i4,108
i1,041
i104
i38
i5,291
Fair
value of plan assets at 31 Decemberg
i41,463
i7,466
i2,680
i1,508
i53,117
Surplus
(deficit) at 31 December
i7,292
(i2,721)
(i5,481)
(i387)
(i1,297)
Represented
by
Asset recognized
i7,567
i269
i59
i62
i7,957
Liability
recognized
(i275)
(i2,990)
(i5,540)
(i449)
(i9,254)
i7,292
(i2,721)
(i5,481)
(i387)
(i1,297)
The
surplus (deficit) may be analysed between funded and unfunded plans as follows
Funded
i7,564
i269
(i109)
(i58)
i7,666
Unfunded
(i272)
(i2,990)
(i5,372)
(i329)
(i8,963)
i7,292
(i2,721)
(i5,481)
(i387)
(i1,297)
The
defined benefit obligation may be analysed between funded and unfunded plans as follows
Funded
(i33,899)
(i7,197)
(i2,789)
(i1,566)
(i45,451)
Unfunded
(i272)
(i2,990)
(i5,372)
(i329)
(i8,963)
(i34,171)
(i10,187)
(i8,161)
(i1,895)
(i54,414)
a The
costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the costs of administering other post-retirement benefit plans are included in the benefit obligation.
b Past service credits represent curtailment gains arising from restructuring programmes in the UK, US and other countries, whilst past service costs and settlements in the Eurozone represent charges for special termination benefits reflecting the increased liability arising as a result of early retirements. Settlement costs in the US resulted from a pension risk transfer to an external carrier for a group of small benefit retirees.
c Most of the contributions made by plan participants into UK pension plans were made under salary sacrifice.
d The
benefit payments amount shown above comprises $i2,935 million benefits and $i428
million settlements, plus $i40 million of plan expenses incurred in the administration of the benefit.
e The benefit obligation for the US is made up of $i7,728
million for pension liabilities and $i2,459 million for other post-retirement benefit liabilities (which are unfunded and are primarily retiree medical liabilities). The benefit obligation for the Eurozone includes $i5,060
million for pension liabilities in Germany which is largely unfunded.
f The actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurement of plan assets as disclosed above.
g The fair value of plan assets includes borrowings related to the LDI programme as described on page 199.
/
bp
Annual Report and Form 20-F 2020
201
24. Pensions and other post-retirement benefits – continued
$
million
2019
UK
US
Eurozone
Other
Total
Analysis of the amount charged to profit or loss
Current service
costa
i227
i263
i81
i38
i609
Past
service costb
i2
i—
i5
(i1)
i6
Settlementb
i—
(i13)
i8
i—
(i5)
Operating
charge relating to defined benefit plans
i229
i250
i94
i37
i610
Payments
to defined contribution plans
i42
i188
i7
i38
i275
Total
operating charge
i271
i438
i101
i75
i885
Interest
income on plan assetsa
(i909)
(i285)
(i43)
(i46)
(i1,283)
Interest
on plan liabilities
i757
i387
i133
i69
i1,346
Other
finance (income) expense
(i152)
i102
i90
i23
i63
Analysis
of the amount recognized in other comprehensive income
Actual asset return less interest income on plan assets
i2,945
i1,079
i220
i97
i4,341
Change
in financial assumptions underlying the present value of the plan liabilities
(i2,294)
(i1,036)
(i748)
(i92)
(i4,170)
Change
in demographic assumptions underlying the present value of the plan liabilities
i136
i91
i3
(i4)
i226
Experience
gains and losses arising on the plan liabilities
(i57)
(i22)
i6
i4
(i69)
Remeasurements
recognized in other comprehensive income
i730
i112
(i519)
i5
i328
Movements
in benefit obligation during the year
Benefit obligation at 1 January
i26,830
i9,696
i6,906
i1,686
i45,118
Exchange
adjustments
i942
i—
(i142)
i26
i826
Operating
charge relating to defined benefit plans
i229
i250
i94
i37
i610
Interest
cost
i757
i387
i133
i69
i1,346
Contributions
by plan participantsc
i20
i—
i2
i6
i28
Benefit
payments (funded plans)d
(i1,207)
(i830)
(i76)
(i75)
(i2,188)
Benefit
payments (unfunded plans)d
(i6)
(i205)
(i273)
(i15)
(i499)
Reclassified
as assets held for sale
i—
(i146)
i—
i—
(i146)
Disposals
i—
i—
(i30)
i—
(i30)
Remeasurements
i2,215
i967
i739
i92
i4,013
Benefit
obligation at 31 Decembera e
i29,780
i10,119
i7,353
i1,826
i49,078
Movements
in fair value of plan assets during the year
Fair value of plan assets at 1 January
i32,085
i7,195
i2,112
i1,290
i42,682
Exchange
adjustments
i1,141
i—
(i43)
i24
i1,122
Interest
income on plan assetsaf
i909
i285
i43
i46
i1,283
Contributions
by plan participantsc
i20
i—
i2
i6
i28
Contributions
by employers (funded plans)
i236
i4
i85
i24
i349
Benefit
payments (funded plans)d
(i1,207)
(i830)
(i76)
(i75)
(i2,188)
Reclassified
as assets held for sale
i—
(i78)
i—
i—
(i78)
Remeasurementsf
i2,945
i1,079
i220
i97
i4,341
Fair
value of plan assets at 31 Decemberg
i36,129
i7,655
i2,343
i1,412
i47,539
Surplus
(deficit) at 31 December
i6,349
(i2,464)
(i5,010)
(i414)
(i1,539)
Represented
by
Asset recognized
i6,588
i387
i27
i51
i7,053
Liability
recognized
(i239)
(i2,851)
(i5,037)
(i465)
(i8,592)
i6,349
(i2,464)
(i5,010)
(i414)
(i1,539)
The
surplus (deficit) may be analysed between funded and unfunded plans as follows
Funded
i6,588
i387
(i136)
(i87)
i6,752
Unfunded
(i239)
(i2,851)
(i4,874)
(i327)
(i8,291)
i6,349
(i2,464)
(i5,010)
(i414)
(i1,539)
The
defined benefit obligation may be analysed between funded and unfunded plans as follows
Funded
(i29,541)
(i7,268)
(i2,479)
(i1,499)
(i40,787)
Unfunded
(i239)
(i2,851)
(i4,874)
(i327)
(i8,291)
(i29,780)
(i10,119)
(i7,353)
(i1,826)
(i49,078)
a The
costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the costs of administering other post-retirement benefit plans are included in the benefit obligation.
b Past service costs and settlements have arisen from restructuring programmes and represent charges for special termination benefits reflecting the increased liability arising as a result of early retirements. Settlements in the US are the result of a buy-out transaction for the pensions of a group of low value annuitants.
c Most of the contributions made by plan participants into UK pension plans were made under salary sacrifice.
d The benefit payments amount shown above comprises
$i2,304 million benefits and $i346
million settlements, plus $i37 million of plan expenses incurred in the administration of the benefit.
e The benefit obligation for the US is made up of $i7,789
million for pension liabilities and $i2,330 million for other post-retirement benefit liabilities (which are unfunded and are primarily retiree medical liabilities). The benefit obligation for the Eurozone includes $i4,567
million for pension liabilities in Germany which is largely unfunded.
f The actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurement of plan assets as disclosed above.
g The fair value of plan assets includes borrowings related to the LDI programme as described on page 199.
202
bp
Annual Report and Form 20-F 2020
Financial statements
24. Pensions and other post-retirement benefits – continued
$
million
2018
UK
US
Eurozone
Other
Total
Analysis of the amount charged to profit or loss
Current
service costa
i295
i299
i84
i43
i721
Past
service costb
i15
i—
i9
i4
i28
Settlement
i—
i—
i17
i—
i17
Operating
charge relating to defined benefit plans
i310
i299
i110
i47
i766
Payments
to defined contribution plans
i38
i178
i5
i40
i261
Total
operating charge
i348
i477
i115
i87
i1,027
Interest
income on plan assetsa
(i868)
(i262)
(i44)
(i45)
(i1,219)
Interest
on plan liabilities
i774
i369
i136
i67
i1,346
Other
finance (income) expense
(i94)
i107
i92
i22
i127
Analysis
of the amount recognized in other comprehensive income
Actual asset return less interest income on plan assets
(i722)
(i256)
(i69)
(i36)
(i1,083)
Change
in financial assumptions underlying the present value of the plan liabilities
i1,770
i945
i14
i65
i2,794
Change
in demographic assumptions underlying the present value of the plan liabilities
i123
(i9)
(i42)
i7
i79
Experience
gains and losses arising on the plan liabilities
i520
i41
(i43)
i9
i527
Remeasurements
recognized in other comprehensive income
i1,691
i721
(i140)
i45
i2,317
a
The costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the costs of administering other post-retirement benefit plans are included in the benefit obligation.
b Past service costs have arisen from restructuring programmes and represent charges for special termination benefits representing the increased liability arising as a result of early retirements mostly in the UK and Eurozone.
Sensitivity analysis
The discount rate, inflation, salary growth and the mortality assumptions all have a significant effect on the amounts reported. iA
one-percentage point change, in isolation, in certain assumptions as at 31 December 2020 for the group’s pensions and other post-retirementbenefit expense would have had the effects shown in the tables below. The effects shown for the expense in 2021 comprise the total of current service cost and net finance income or expense.
$
million
One percentage point
UK
US
Eurozone
Increase
Decrease
Increase
Decrease
Increase
Decrease
Discount
ratea
Effect on expense in 2021
(i274)
i198
(i51)
i36
(i2)
(i11)
Effect
on obligation at 31 December 2020
(i5,658)
i7,690
(i1,272)
i1,556
(i1,149)
i1,452
Inflation
rateb
Effect on expense in 2021
i145
(i116)
i10
(i8)
i35
(i28)
Effect
on obligation at 31 December 2020
i5,337
(i4,482)
i66
(i55)
i1,025
(i870)
Salary
growth
Effect on expense in 2021
i31
(i27)
i12
(i10)
i7
(i7)
Effect
on obligation at 31 December 2020
i670
(i585)
i82
(i69)
i91
(i89)
a The
amounts presented reflect that the discount rate is used to determine the asset interest income as well as the interest cost on the obligation.
b The amounts presented reflect the total impact of an inflation rate change on the assumptions for rate of increase in salaries, pensions in payment and deferred pensions.
i
$
million
One year increase
UK
US
Eurozone
Longevity
Effect on expense in 2021
i28
i5
i8
Effect
on obligation at 31 December 2020
i1,406
i150
i333
/
Estimated
future benefit payments and the weighted average duration of defined benefit obligations
i
The expected benefit payments, which reflect expected future service, as appropriate, but exclude plan expenses, up until 2030 and the weighted average duration of the defined benefit obligations at 31 December 2020 are as follows:
$
million
Estimated future benefit payments
UK
US
Eurozone
Other
Total
2021
i1,072
i1,568
i357
i112
i3,109
2022
i1,086
i612
i346
i109
i2,153
2023
i1,120
i593
i339
i107
i2,159
2024
i1,141
i575
i332
i108
i2,156
2025
i1,135
i583
i328
i107
i2,153
2026-2030
i5,939
i2,696
i1,521
i528
i10,684
Years
Weighted
average duration
i19.2
i13.8
i16.1
i12.7
/
bp
Annual Report and Form 20-F 2020
203
25.iCash and cash equivalents
i
$
million
2020
2019
Cash
i6,235
i6,462
Triparty
repos and term bank deposits
i17,368
i10,296
Cash
equivalents (excluding triparty repos and term bank deposits)
i7,508
i5,714
i31,111
i22,472
/
Cash
and cash equivalents comprise cash in hand; current balances with banks and similar institutions; deposits of three months or less with banks and similar institutions; money market funds and commercial paper. The carrying amounts of cash, triparty repos and term bank deposits approximate their fair values. Substantially all of the other cash equivalents are categorized within level 1 of the fair value hierarchy.
Cash and cash equivalents at 31 December 2020 includes $i1,917 million (2019 $i1,676
million) that is restricted. The restricted cash balances include amounts required to cover initial margin on trading exchanges and certain cash balances which are subject to exchange controls.
The group holds $i3,890 million (2019 $i4,678
million) of cash and cash equivalents outside the UK and it is not expected that any significant tax will arise on repatriation.
26. iFinance debt
i
$
million
2020
2019
Current
Non-current
Total
Current
Non-current
Total
Borrowings
i9,359
i63,305
i72,664
i10,487
i57,237
i67,724
/
The
main elements of current borrowings are the current portion of long-term borrowings that is due to be repaid in the next 12 months of $i8,122 million (2019 $i8,166
million) and issued commercial paper of $i1,004 million (2019 $i2,279
million). Finance debt does not include accrued interest, which is reported within other payables. As part of actively managing its debt portfolio, during the year the group bought back $i4.0 billion equivalent (2019 $inil)
of euro and sterling bonds and terminated derivatives associated with the debt bought back. In addition on 18 December 2020 the group exercised its option to redeem finance debt with an outstanding aggregate principal amount of $i2.0 billion on 22 January 2021. On 19 March 2021 the group bought back a further $i1.9 billion
equivalent of euro and sterling bonds and terminated associated derivatives. These transactions have no significant impact on net debt or gearing.
The following table shows the weighted-average interest rates achieved through a combination of borrowings and derivative financial instruments entered into to manage interest rate and currency exposures.
Fixed
rate debt
Floating rate debt
Total
Weighted average interest rate %
Weighted average time for which rate is fixed Years
Amount $ million
Weighted average interest rate %
Amount $ million
Amount $ million
2020
US
dollar
i3
i8
i39,452
i2
i32,891
i72,343
Other
currencies
i6
i9
i178
i5
i143
i321
i39,630
i33,034
i72,664
2019
US
dollar
i4
i5
i25,634
i3
i41,871
i67,505
Other
currencies
i6
i10
i183
i7
i36
i219
i25,817
i41,907
i67,724
Fair
values
The estimated fair value of finance debt is shown in the table below together with the carrying amount as reflected in the balance sheet.
Long-term borrowings in the table below include the portion of debt that matures in the 12 months from 31 December 2020, whereas in the group balance sheet the amount is reported within current finance debt.
i
The carrying amount of the group’s short-term borrowings, comprising mainly of commercial paper, approximates
their fair value. The fair values of the significant majority of the group’s long-term borrowings are determined using quoted prices in active markets, and so fall within level 1 of the fair value hierarchy. Where quoted prices are not available, quoted prices for similar instruments in active markets are used and such measurements are therefore categorized in level 2 of the fair value hierarchy.
$
million
2020
2019
Fair value
Carrying amount
Fair value
Carrying amount
Short-term borrowings
i1,237
i1,237
i2,321
i2,321
Long-term
borrowings
i74,855
i71,427
i67,055
i65,403
Total
finance debt
i76,092
i72,664
i69,376
i67,724
/
204
bp
Annual Report and Form 20-F 2020
Financial statements
27.iCapital
disclosures and net debt
The group defines capital as total equity plus net debt. We maintain our financial framework to support the pursuit of value growth for shareholders, while ensuring a secure financial base.
The group monitors capital on basis of gearing, that is, the ratio of net debt to net debt plus equity. Net debt is calculated as finance debt, as shown in the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign exchange and interest rate risks relating to finance debt for which hedge accounting is applied, less cash and cash equivalents. Net debt and gearing are non-GAAP measures. bp believes these measures provide useful information to investors. Net debt enables investors to see the economic effect of finance debt, related hedges and cash and cash equivalents in total. Gearing
enables investors to see how significant net debt is relative to total equity. The derivatives are reported on the balance sheet within the headings ‘Derivative financial instruments’. All components of equity are included in the denominator of the calculation.
i
At 31 December 2020, gearing was i31.3%
(2019 i31.1%).
$ million
At 31 December
2020
2019
Finance
debt
i72,664
i67,724
Less:
fair value asset (liability) of hedges related to finance debta
i2,612
(i190)
i70,052
i67,914
Less:
cash and cash equivalents
i31,111
i22,472
Net
debt
i38,941
i45,442
Total
equityb
i85,568
i100,708
Gearing
i31.3
%
i31.1
%
aDerivative
financial instruments entered into for the purpose of managing interest rate and foreign currency exchange risk associated with net debt with a fair value liability position of $i236 million (2019 liability of $i601
million) are not included in the calculation of net debt shown above as hedge accounting was not applied for these instruments.
b Total equity in 2020 includes perpetual hybrid bonds issued on 17 June 2020. See Note 32 for further information.
/
i
An
analysis of changes in liabilities arising from financing activities is provided below.
$ million
Finance debt
Currency
swapsa
Lease liabilities
Net partner payable for leases entered into on behalf of joint operations
Total liabilities arising from financing activities
At 1 January 2020
i67,724
i918
i9,722
i290
i78,654
Exchange
adjustments
i349
i—
i181
i4
i534
Net
financing cash flow
i1,589
(i226)
(i2,442)
(i40)
(i1,119)
Fair
value (gains) losses
i2,612
(i3,734)
i—
i—
(i1,122)
New
and remeasured leases/joint operation payables
i—
i—
i1,579
i20
i1,599
Other
movements
i390
i77
i222
(i7)
i682
At
31 December 2020
i72,664
(i2,965)
i9,262
i267
i79,228
At
1 January 2019
i65,132
i1,486
i667
i—
i67,285
Adjustment
on adoption of IFRS16
i—
i—
i9,233
i217
i9,450
Exchange
adjustments
(i62)
i—
(i4)
i8
(i58)
Net
financing cash flow
i1,671
i2
(i2,372)
(i14)
(i713)
Fair
value (gains) losses
i924
(i570)
i—
i—
i354
New
and remeasured leases/joint operations payables
i—
i—
i2,614
i82
i2,696
Other
movements
i59
i—
(i416)
(i3)
(i360)
At
31 December 2019
i67,724
i918
i9,722
i290
i78,654
a Previously
reported in this column were hedge accounted derivatives related to finance debt. This has been updated in 2020 as described below and comparatives provided on a consistent basis. Currency swaps include cross currency interest rate swaps.
/
The balances above do not include accrued interest, which is reported within other receivables and other payables on the balance sheet and for which the associated cash flows are presented as operating cash flows in the group cash flow statement. The currency swaps are reported on the balance sheet within the headings 'Derivative financial instruments' and are subsets of both derivatives held for trading and derivatives designated in fair value hedge relationships as detailed in Note 30. When hedge accounting
is applied to these derivatives they are included in the calculation of net debt shown above.
bp Annual Report and Form 20-F 2020
205
28.iLeases
The group leases a number of assets as part of its activities. This primarily includes drilling rigs in the Upstream segment and retail service stations, oil depots and storage tanks in the Downstream segment as well as office accommodation and vessel charters across the group. The weighted-average remaining lease term for the total lease portfolio is around i8
years (2019 i9 years). Some leases will have payments that vary with market interest or inflation rates. Certain leases contain residual value guarantees, which may be triggered in certain circumstances such as if market values have significantly declined at the conclusion of the lease.
i
The
table below shows the timing of the undiscounted cash outflows for the lease liabilities included on the balance sheet.
$ million
2020
2019
Undiscounted lease liability cash flows due:
Within
1 year
i2,262
i2,514
1
to 2 years
i1,672
i1,839
2
to 3 years
i1,340
i1,364
3
to 4 years
i1,025
i1,105
4
to 5 years
i878
i876
5
to 10 years
i2,192
i2,427
Over
10 years
i1,515
i1,174
i10,884
i11,299
Impact
of discounting
(i1,622)
(i1,577)
Lease
liabilities at 31 December
i9,262
i9,722
Of
which – current
i1,933
i2,067
–
non-current
i7,329
i7,655
/
The
group may enter into lease arrangements a number of years before taking control of the underlying asset due to construction lead times or to secure future operational requirements. The total undiscounted amount for future commitments for leases not yet commenced as at 31 December 2020 is $i5,309 million (2019 $i5,688 million).
The majority of this future commitment relates to the floating LNG vessel to service the Greater Tortue Ahmeyim project from 2023.
i
$
million
2020
2019
Total cash outflow for amounts included in lease liabilitiesa
i2,779
i2,709
Expense
for variable payments not included in the lease liability
i41
i67
Short-term
lease expense
i621
i331
Additions
to right-of-use assets in the period
i1,714
i2,542
Gain
on sale and leaseback transactions
i187
i—
/
a
The cash outflows for amounts not included in lease liabilities approximate the income statement expense disclosed above.
An analysis of right-of-use assets and depreciation is provided in Note 12. An analysis of lease interest expense is provided in Note 7.
29.iFinancial instruments
and financial risk factors
i
The accounting classification of each category of financial instruments and their carrying amounts are set out below.
$
million
At 31 December 2020
Note
Measured at amortized cost
Mandatorily measured at fair value through profit or loss
Derivative hedging instruments
Total carrying amount
Financial assets
Other investments
18
—
i3,079
—
i3,079
Loans
i929
i369
—
i1,298
Trade
and other receivables
20
i20,252
—
—
i20,252
Derivative
financial instruments
30
—
i10,049
i2,698
i12,747
Cash
and cash equivalents
25
i24,905
i6,206
—
i31,111
Financial
liabilities
Trade and other payables
22
(i44,960)
—
—
(i44,960)
Derivative
financial instruments
30
—
(i8,320)
(i82)
(i8,402)
Accruals
(i5,502)
—
—
(i5,502)
Lease
liabilities
28
(i9,262)
—
—
(i9,262)
Finance
debt
26
(i72,664)
—
—
(i72,664)
(i86,302)
i11,383
i2,616
(i72,303)
/
206
bp
Annual Report and Form 20-F 2020
Financial statements
29. Financial instruments and financial risk factors – continued
$
million
At 31 December 2019
Note
Measured at amortized cost
Mandatorily measured at fair value through profit or loss
Derivative hedging instruments
Total carrying amount
Financial assets
Other investments
18
—
i1,445
—
i1,445
Loans
i906
i63
—
i969
Trade
and other receivables
20
i24,271
—
—
i24,271
Derivative
financial instruments
30
—
i9,984
i483
i10,467
Cash
and cash equivalents
25
i18,183
i4,289
—
i22,472
Financial
liabilities
Trade and other payables
22
(i55,891)
—
—
(i55,891)
Derivative
financial instruments
30
—
(i8,122)
(i676)
(i8,798)
Accruals
(i6,062)
—
—
(i6,062)
Lease
liabilities
28
(i9,722)
—
—
(i9,722)
Finance
debt
26
(i67,724)
—
—
(i67,724)
(i96,039)
i7,659
(i193)
(i88,573)
The fair value of finance debt is shown in Note 26. For all other financial instruments within the scope of IFRS 9, the carrying amount is either the fair value, or approximates the fair value.
Information on gains and losses on derivative financial assets and financial liabilities classified as measured at fair value through profit or loss is provided in the derivative gains and losses section of Note 30. Fair value gains and losses related to other assets and liabilities classified as measured at fair value through profit or loss totalled a net gain of $i367
million (2019 net loss of $i129 million). Dividend income of $i17
million (2019 $i20 million) from investments in equity instruments classified as measured at fair value through profit or loss is presented within other income - see Note 7.
Interest income and expenses arising on financial instruments are disclosed in Note 7.
Financial risk factors
The
group is exposed to a number of different financial risks arising from natural business exposures as well as its use of financial instruments including market risks relating to commodity prices; foreign currency exchange rates and interest rates; credit risk; and liquidity risk.
The group financial risk committee (GFRC) advises the group chief financial officer (CFO) who oversees the management of these risks. The GFRC is chaired by the CFO and consists of a group of senior managers including the group treasurer and the heads of the group finance, tax and the integrated supply and trading functions. The purpose of the committee is to advise on financial risks and the appropriate financial risk governance framework for the group. The committee provides assurance to the CFO and the group chief executive (GCE), and via the GCE to the board, that the group’s financial risk-taking activity is governed by appropriate policies and
procedures and that financial risks are identified, measured and managed in accordance with group policies and group risk appetite.
The group’s trading activities in the oil, natural gas, LNG and power markets are managed within the integrated supply and trading function. Treasury holds foreign exchange and interest-rate products in the financial markets to hedge group exposures related to debt and hybrid bond issuance; the compliance, control, and risk management processes for these activities are managed within the treasury function. All other foreign exchange and interest rate activities within financial markets are performed within the integrated supply and trading function and are also underpinned by the compliance, control and risk management infrastructure common to the activities of bp’s integrated supply and trading function. All derivative activity is carried out by specialist teams that have the appropriate skills,
experience and supervision. These teams are subject to close financial and management control.
The integrated supply and trading function maintains formal governance processes that provide oversight of market risk, credit risk and operational risk associated with trading activity. A policy and risk committee approves value-at-risk delegations, reviews incidents and validates risk-related policies, methodologies and procedures. A commitments committee approves the trading of new products, instruments and strategies and material commitments.
In addition, the integrated supply and trading function undertakes derivative activity for risk management purposes under a control framework as described more fully below.
(a) Market risk
Market risk is the risk or uncertainty arising from possible market
price movements and their impact on the future performance of a business. The primary commodity price risks that the group is exposed to include oil, natural gas and power prices that could adversely affect the value of the group’s financial assets, liabilities or expected future cash flows. The group enters into derivatives in a well-established entrepreneurial trading operation. In addition, the group has developed a control framework aimed at managing the volatility inherent in certain of its natural business exposures. In accordance with the control framework the group enters into various transactions using derivatives for risk management purposes.
The major components of market risk are commodity price risk, foreign currency exchange risk and interest rate risk, each of which is discussed below.
(i) Commodity price risk
The group’s
integrated, supply and trading function is responsible for delivering value across the overall crude, oil products, gas and power supply chains. As such, it routinely enters into spot and term physical commodity contracts in addition to optimising physical storage, pipeline and transportation capacity. These activities expose the group to commodity price risk which is managed by entering into oil and natural gas swaps, options and futures.
The group measures market risk exposure arising from its trading positions in liquid periods using value-at-risk techniques based on Variance/Covariance or Monte Carlo simulation models. These techniques make a statistical assessment of the market risk arising from possible future changes in market prices over a one-day holding period within a 95% confidence level. The value-at-risk measure is supplemented
by stress testing and scenario analysis through simulating the financial impact of certain physical, economic and geo-political scenarios. Trading activity occurring in liquid periods is
bp Annual Report and Form 20-F 2020
207
29. Financial
instruments and financial risk factors – continued
subject to value-at-risk and other limits for each trading activity and the aggregate of all trading activity. The board has delegated a limit of $i100 million (2019 $i100
million) value at risk in support of this trading activity. Alternative measures are used to monitor exposures which are outside liquid periods and for which value-at-risk techniques are not appropriate.
(ii) Foreign currency exchange risk
Since bp has global operations, fluctuations in foreign currency exchange rates can have a significant effect on the group’s reported results and future expenditure commitments. The effects of most exchange rate fluctuations are absorbed in business operating results through changing cost competitiveness, lags in market adjustment to movements in rates and translation differences accounted for on specific transactions. For this reason, the total effect of exchange rate fluctuations is not identifiable separately in the group’s reported results. The main underlying economic currency of the group’s cash flows is the US dollar. This is because bp’s
major product, oil, is priced internationally in US dollars. bp’s foreign currency exchange management policy is to limit economic and material transactional exposures arising from currency movements against the US dollar. The group co-ordinates the handling of foreign currency exchange risks centrally, by netting off naturally-occurring opposite exposures wherever possible and then managing any material residual foreign currency exchange risks.
Most of the group’s borrowings are in US dollars or are hedged with respect to the US dollar. At 31 December 2020, the total foreign currency borrowings not swapped into US dollars amounted to $i321
million (2019 $i219 million). During the year the group issued perpetual subordinated hybrid bonds in euro, sterling and US dollars. Whilst the contractual terms of these instruments allow the group to defer coupon payments and the repayment of principal indefinitely, the group has chosen to manage the foreign currency exposure relating to the non-US dollar hybrid bonds to their respective first call periods.
The group manages the net residual foreign currency exposures by constantly reviewing the foreign currency economic
value at risk and aims to manage such risk to keep the 12-month foreign currency value at risk below $i400 million. At no point over the past ithree years did the value at risk exceed the maximum risk limit. A continuous
assessment is made in respect to the group’s foreign currency exposures to capture hedging requirements.
During the year, hedge accounting was applied to foreign currency exposure to highly probable forecast capital expenditure commitments. The group fixes the US dollar cost of non-US dollar supplies by using currency forwards for the highly probable forecast capital expenditure; the exposures are in sterling, euro, Australian dollar and Korean won. At 31 December 2020 the most significant open contracts in place were for $i124 million
sterling (2019 $i106 million sterling).
Where the group enters into foreign currency exchange contracts for entrepreneurial trading purposes the activity is controlled using trading value-at-risk techniques as explained in (i) commodity price risk above.
(iii) Interest rate risk
bp is also exposed to interest rate risk from the possibility that changes in interest rates
will affect future cash flows or the fair values of its financial instruments, principally finance debt. While the group issues debt and hybrid bonds in a variety of currencies based on market opportunities, it uses derivatives to swap the economic exposure to a floating rate basis, mainly to US dollar floating, but in certain defined circumstances maintains a US dollar fixed rate exposure for a proportion of debt. The proportion of floating rate debt net of interest rate swaps at 31 December 2020 was i45%
of total finance debt outstanding (2019 i62%). The weighted average interest rate on finance debt at 31 December 2020 was i3%
(2019 i3%) and the weighted average maturity of fixed rate debt was ieight years (2019 ifive
years).
The group’s earnings are sensitive to changes in interest rates on the element of the group’s finance debt that has been swapped to floating rates. If the interest rates applicable to these floating rate instruments were to have changed by one percentage point on 1 January 2021, it is estimated that the group’s finance costs for 2021 would change by approximately $i330
million (2019 $i419 million).
Financial authorities in the US, UK, EU and other territories are currently undertaking reviews of key interest rate benchmarks such as the London Inter-bank Offered Rate (LIBOR) with a view to replacing them with alternative benchmarks. bp is significantly exposed to benchmark interest rate components; predominantly USD LIBOR, GBP LIBOR,
EURIBOR and CHF LIBOR. Following the completion of consultation processes, these financial authorities have begun to announce the timing of both benchmark transitions and continued publication of synthetic benchmarks.
In October 2020 the International Swaps and Derivatives Association (ISDA) published its fallback protocol containing clauses to amend derivative contracts on the cessation of LIBOR should an entity and its counterparties adhere to the protocol. The protocol’s pricing mechanism is at fair market value and bp has signed up to the protocol as this removes transition uncertainty for any interest rate and cross-currency interest rate swap contracts of the Group without fall-back clauses. The ISDA fallback protocol
is expected to increase market activity and certainty such that corporates can finalize their plans for implementation of the transition. bp continues to monitor regulatory and market developments over the course of the transition.
In response to the cessation of the interbank offered rates (IBORs), bp has set up an internal working group to monitor market developments and manage the transition to alternative benchmark rates and is currently assessing the impact on contracts and arrangements that are linked to existing interest rate benchmarks, for example, borrowings, leases and derivative contracts. bp is also participating on external committees and task forces dedicated to interest rate benchmark
reform.
(b) Credit risk
Credit risk is the risk that a customer or counterparty to a financial instrument will fail to perform or fail to pay amounts due causing financial loss to the group and arises from cash and cash equivalents, derivative financial instruments and deposits with financial institutions and principally from credit exposures to customers relating to outstanding receivables. Credit exposure also exists in relation to guarantees issued by group companies under which the outstanding exposure incremental to that recognized on the balance sheet at 31 December 2020 was $i1,405
million (2019 $i692 million) in respect of liabilities of joint ventures and associates and $i661
million (2019 $i523 million) in respect of liabilities of other third parties.
The group has a credit policy, approved by the CFO that is designed to ensure that consistent processes are in place throughout the group to measure and control credit risk. Credit risk is considered as part of the risk-reward balance of doing business. On entering into any business contract
the extent to which the arrangement exposes the group to credit risk is considered. Key requirements of the policy include segregation of credit approval authorities from any sales, marketing or trading teams authorized to incur credit risk; the establishment of credit systems and processes to ensure that all counterparty exposure is rated and that all counterparty exposure and limits can be monitored and reported; and the timely identification and reporting of any non-approved credit exposures and credit losses. While each segment is responsible for its own credit risk management and reporting consistent with group policy, the treasury function holds group-wide credit risk authority and oversight responsibility for exposure to banks and financial institutions. Standing credit controls and processes were augmented intra-year given heightened uncertainty from increased oil price volatility and the evolving COVID-19 pandemic. Constraints on incoming credit risks were tightened,
credit reporting and frequency was enhanced from the operational to board level, and key credit risk strategies were reviewed and vetted.
208
bp Annual Report and Form 20-F 2020
Financial
statements
29. Financial instruments and financial risk factors – continued
For the purposes of financial reporting the group calculates expected loss allowances based on the maximum contractual period over which the group is exposed to credit risk. Lifetime expected credit losses are recognized for trade receivables and the credit risk associated with the significant majority of financial assets measured at amortized cost is considered to be low. Since the tenor of substantially all of the group's in-scope financial assets is less than 12 months there is no significant difference between the measurement of 12-month and lifetime expected credit losses. Expected loss allowances for financial guarantee contracts are typically lower than their initial
fair value less, where appropriate, amortization. Financial assets are considered to be credit-impaired when there is reasonable and supportable evidence that one or more events that have a detrimental impact on the estimated future cash flows of the financial asset have occurred. This includes observable data concerning significant financial difficulty of the counterparty; a breach of contract; concession being granted to the counterparty for economic or contractual reasons relating to the counterparty’s financial difficulty, that would not otherwise be considered; it becoming probable that the counterparty will enter bankruptcy or other financial re-organization or an active market for the financial asset disappearing because of financial difficulties. The group also applies a rebuttable presumption that an asset is credit-impaired when contractual payments are more than 30 days
past due. Where the group has no reasonable expectation of recovering a financial asset in its entirety or a portion thereof, for example where all legal avenues for collection of amounts due have been exhausted, the financial asset (or relevant portion) is written off.
The measurement of expected credit losses is a function of the probability of default, loss given default (i.e. the magnitude of the loss after recovery if there is a default) and the exposure at default (i.e. the asset's carrying amount). The group allocates a credit risk rating to exposures based on data that is determined to be predictive of the risk of loss, including but not limited to external ratings. Probabilities of default derived from historical, current and future-looking market data are assigned by credit risk rating with a loss given default based on historical experience and relevant market and academic research applied by exposure type. Experienced
credit judgement is applied to ensure probabilities of default are reflective of the credit risk associated with the group's exposures. Credit enhancements that would reduce the group's credit losses in the event of default are reflected in the calculation when they are considered integral to the related asset.
The maximum credit exposure associated with financial assets is equal to the carrying amount. The group does not aim to remove credit risk entirely but expects to experience a certain level of credit losses. As at 31 December 2020, the group had in place credit enhancements designed to mitigate approximately $i5.4
billion (2019 $i7.0 billion) of credit risk, of which substantially all relates to assets in the scope of IFRS 9's impairment requirements. Credit enhancements include standby and documentary letters of credit, bank guarantees, insurance and liens which are typically taken out with financial institutions who have investment grade credit ratings, or are liens over assets held by the counterparty of the related receivables. Reports are regularly prepared and presented to the GFRC that cover the group’s overall credit
exposure and expected loss trends, exposure by segment, and overall quality of the portfolio.
i
Management information used to monitor credit risk, which reflects the impact of credit enhancements, indicates that the risk profile of financial assets which are subject to review for impairment under IFRS 9 is as set out below.
%
As
at 31 December
2020
2019
AAA to AA-
i11
%
i16
%
A+
to A-
i59
%
i51
%
BBB+
to BBB-
i8
%
i13
%
BB+
to BB-
i6
%
i7
%
B+
to B-
i13
%
i11
%
CCC+
and below
i3
%
i2
%
/
Movements
in the impairment provision for trade and other receivables are shown in Note 21.
ii
Financial instruments subject to offsetting, enforceable master netting arrangements
and similar agreements
The following table shows the amounts recognized for financial assets and liabilities which are subject to offsetting arrangements on a gross basis, and the amounts offset in the balance sheet.
Amounts which cannot be offset under IFRS, but which could be settled net under the terms of master netting agreements if certain conditions arise, and collateral received or pledged, are also presented in the table to show the total net exposure of the group.
$
million
Gross amounts of recognized financial assets (liabilities)
Amounts set off
Net amounts presented on the balance sheet
Related amounts not set off in the balance sheet
Net amount
At 31 December 2020
Master netting arrangements
Cash collateral (received) pledged
Derivative assets
i14,765
(i2,019)
i12,746
(i2,075)
(i386)
i10,285
Derivative
liabilities
(i10,414)
i2,019
(i8,395)
i2,075
i—
(i6,320)
Trade
and other receivables
i7,667
(i3,679)
i3,988
(i693)
(i122)
i3,173
Trade
and other payables
(i7,862)
i3,679
(i4,183)
i693
i—
(i3,490)
At
31 December 2019
Derivative assets
i13,191
(i2,724)
i10,467
(i1,971)
(i206)
i8,290
Derivative
liabilities
(i11,445)
i2,724
(i8,721)
i1,971
i—
(i6,750)
Trade
and other receivables
i10,661
(i5,211)
i5,450
(i961)
(i190)
i4,299
Trade
and other payables
(i10,266)
i5,211
(i5,055)
i961
i—
(i4,094)
//
bp
Annual Report and Form 20-F 2020
209
29. Financial instruments and financial risk factors – continued
(c) Liquidity risk
Liquidity risk is the risk that suitable sources of funding for the group’s business activities may not be available. The group’s liquidity is managed centrally with operating units forecasting their cash and currency requirements to the central treasury function. Unless restricted by local regulations, generally subsidiaries pool their cash surpluses to the treasury function, which will then arrange to fund
other subsidiaries’ requirements, or invest any net surplus in the market or arrange for necessary external borrowings, while managing the group’s overall net currency positions.
The group benefits from open credit provided by suppliers who generally sell on five to 60-day payment terms in accordance with industry norms. bp utilizes various arrangements in order to manage its working capital and reduce volatility in cash flow. This includes discounting of receivables and, in the supply and trading businesses, managing inventory, collateral and supplier payment terms within a maximum of 60 days.
It is normal practice in the oil and gas supply and trading business for customers and suppliers to utilise letter of credit (LC) facilities to mitigate credit and non-performance risk. Consequently,
LCs facilitate active trading in a global market where credit and performance risk can be significant. In common with the industry, bp routinely provides LCs to some of its suppliers.
The group has committed LC facilities totalling $i11,325 million (2019 $i12,175
million), allowing LCs to be issued for a maximum i24-month duration. There were also uncommitted secured LC facilities in place at 31 December 2020 for $i3,460 million (2019 $i4,440
million), which are secured against inventories or receivables when utilized. The facilities are held with over i25 international banks. The uncommitted secured LC facilities can only be terminated by either party giving a stipulated termination notice to the other.
In certain circumstances, the supplier has the option to request accelerated payment from the LC provider in order to further reduce their exposure. bp’s payments are made to the provider of the LC rather than the supplier according to the original contractual payment terms. At 31 December 2020, $i5,250
million (2019 $i4,755 million) of the group’s trade payables subject to these arrangements were payable to LC providers, with no material exposure to any individual provider. If these facilities were not available, this could result in renegotiation of payment terms with suppliers such that settlement periods were shorter.
Standard & Poor’s Ratings long-term credit rating for bp is A- (negative outlook) and Moody’s Investors Service rating is A1 (negative outlook) and the Fitch Ratings' long-term
credit rating is A (stable).
During 2020, $i14 billion (2019 $i8 billion) of long-term
taxable bonds were issued with terms ranging from two to ithirty years. In addition the group issued perpetual hybrid bonds with a US dollar equivalent value of $i11.9 billion.
Commercial paper is issued at competitive rates to meet short-term borrowing requirements as and when needed.
As a further liquidity measure, the group continues to maintain suitable levels of cash and cash equivalents, amounting to $i31.1 billion at 31 December 2020 (2019 $i22.5
billion), primarily invested with highly rated banks or money market funds and readily accessible at immediate and short notice. At 31 December 2020, the group had substantial amounts of undrawn borrowing facilities available, consisting of an undrawn committed $i10.0 billion credit facility and $i7.6 billion
(2019 $i7.6 billion) of standby facilities. On 1st March 2021, following an assessment of liquidity requirements, the group replaced these with new facility agreements, consisting of an undrawn committed $i8.0 billion
credit facility and $i4.0 billion of standby facilities. The facilities are available for three and five years respectively at pre-agreed margins and are with i27 international banks, and borrowings under them would
be at pre-agreed rates.
For further information on the group's sources and uses of cash see Liquidity and capital resources on page 306.
The group manages liquidity risk associated with derivative contracts, other than derivative hedging instruments, based on the expected maturities of both derivative assets and liabilities as indicated in Note 30. Management does not currently anticipate any cash flows, other than noted below, that could be of a significantly different amount or could occur earlier than the expected maturity analysis provided.
i
The
table below shows the timing of cash outflows relating to finance debt, trade and other payables and accruals. As part of actively managing the group’s debt portfolio it is possible that cash flows in relation to finance debt could be accelerated from the profile provided. As a result of the 19 March 2021 debt buy back (see Note 26 for further information) $i1.9 billion equivalent of cash outflows relating to finance debt that are presented in the table with maturities of 2-8 years have occurred within one year of the balance sheet date.
$ million
2020
2019
Trade and
other
payablesa
Accruals
Finance debt
Interest
on finance debt
Trade and
other
payablesa
Accruals
Finance
debtb
Interest on finance debt
Within one year
i33,290
i4,650
i9,119
i1,778
i43,699
i5,066
i10,065
i2,037
1
to 2 years
i1,728
i157
i6,292
i1,477
i1,937
i261
i6,726
i1,641
2
to 3 years
i1,590
i184
i7,031
i1,305
i1,465
i146
i7,949
i1,409
3
to 4 years
i1,332
i87
i8,047
i1,110
i1,409
i181
i7,022
i1,172
4
to 5 years
i1,335
i217
i6,652
i919
i1,332
i108
i7,554
i942
5
to 10 years
i4,570
i108
i22,156
i2,408
i5,863
i231
i23,540
i1,970
Over
10 years
i4,419
i99
i10,008
i1,037
i3,957
i69
i2,497
i249
i48,264
i5,502
i69,305
i10,034
i59,662
i6,062
i65,353
i9,420
a
2020 includes $i14,569 million (2019 $i16,129 million) in relation to the Gulf of Mexico oil spill, of which $i13,160
million (2019 $i14,501 million) matures in greater than one year.
/
210
bp
Annual Report and Form 20-F 2020
Financial statements
29. Financial instruments and financial risk factors – continued
i
The
table below shows the timing of cash outflows for derivative financial instruments entered into for the purpose of managing interest rate and foreign currency exchange risk, whether or not hedge accounting is applied, based upon contractual payment dates. As part of actively managing the group’s debt portfolio it is possible that cash flows in relation to associated derivatives could be accelerated from the profile provided. The amounts reflect the gross settlement amount where the pay leg of a derivative will be settled separately from the receive leg, as in the case of cross-currency swaps hedging non-US dollar finance debt or hybrid bonds. The swaps are with high investment-grade counterparties and therefore the settlement-day risk exposure is considered to be negligible. Not shown in the table are the gross settlement amounts (inflows) for the receive leg of derivatives that are settled separately from the pay leg, which amount to $i33,704
million at 31 December 2020 (2019 $i24,787 million) to be received on the same day as the related cash outflows. As a result of the termination of derivatives associated with the 19 March 2021 debt buy back (see Note 26 for further information) $i1.8 billion
of cash outflows that are presented in the table with maturities of 2-8 years and $i1.9 billion equivalent of cash inflows on the receive legs have occurred within one year of the balance sheet date.
$
million
Cash outflows for derivative financial instruments at 31 December
2020
2019
Within one year
i2,384
i1,678
1
to 2 years
i1,976
i2,384
2
to 3 years
i2,017
i2,838
3
to 4 years
i3,074
i2,906
4
to 5 years
i2,582
i3,321
5
to 10 years
i15,263
i10,633
Over
10 years
i4,483
i2,224
i31,779
i25,984
For
further information on our derivative financial instruments, see Note 30.
/
30.iDerivative financial instruments
In
the normal course of business the group enters into derivative financial instruments (derivatives) to manage its normal business exposures in relation to commodity prices, foreign currency exchange rates and interest rates, including management of the balance between floating rate and fixed rate debt, consistent with risk management policies and objectives. An outline of the group’s financial risks and the objectives and policies pursued in relation to those risks is set out in Note 29. Additionally, the group has a well-established entrepreneurial trading operation that is undertaken in conjunction with these activities using a similar range of contracts.
For information on significant estimates and judgements made in relation to the valuation of derivatives see Derivative financial instruments within Note 1.
i
The
fair values of derivative financial instruments at 31 December are set out below.
Exchange traded derivatives are valued using closing prices provided by the exchange as at the balance sheet date. These derivatives are categorized within level 1 of the fair value hierarchy. Exchange traded derivatives are typically considered settled through the (normally daily) payment or receipt of variation margin.
Over-the-counter (OTC) financial swaps and physical commodity sale and purchase contracts are generally valued using readily available information in the public markets and quotations provided by brokers and price index developers. These quotes are corroborated with market data and are categorized within level 2 of the fair value hierarchy.
In certain
less liquid markets, or for longer-term contracts, forward prices are not as readily available. In these circumstances, OTC financial swaps and physical commodity sale and purchase contracts are valued using internally developed methodologies that consider historical relationships between various commodities, and that result in management’s best estimate of fair value. These contracts are categorized within level 3 of the fair value hierarchy.
bp
Annual Report and Form 20-F 2020
211
30. Derivative financial instruments – continued
Financial OTC and physical commodity options are valued using industry standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and contractual prices for the underlying instruments, as well as other relevant economic factors. The degree to which these inputs are observable in the forward markets determines whether the option is categorized within level 2 or level 3 of the fair value hierarchy.
$
million
2020
2019
Fair value asset
Fair value liability
Fair value asset
Fair value liability
Derivatives held for trading
Currency derivatives
i858
(i694)
i81
(i744)
Oil
price derivatives
i1,519
(i1,093)
i1,918
(i1,478)
Natural
gas price derivatives
i6,406
(i5,489)
i6,569
(i4,871)
Power
price derivatives
i1,258
(i1,037)
i1,306
(i952)
Other
derivatives
i7
i—
i110
i—
i10,048
(i8,313)
i9,984
(i8,045)
Embedded
derivatives
Other embedded derivatives
i1
(i7)
i—
(i77)
i1
(i7)
i—
(i77)
Cash
flow hedges
Currency forwards
i4
i—
i1
(i4)
Gas
price futures
i—
i—
i—
i—
i4
i—
i1
(i4)
Fair
value hedges
Currency swaps
i2,614
(i82)
i344
(i637)
Interest
rate swaps
i80
i—
i138
(i35)
i2,694
(i82)
i482
(i672)
i12,747
(i8,402)
i10,467
(i8,798)
Of
which – current
i2,992
(i2,998)
i4,153
(i3,261)
–
non-current
i9,755
(i5,404)
i6,314
(i5,537)
Derivatives
held for trading
The group maintains active trading positions in a variety of derivatives. The contracts may be entered into for risk management purposes, to satisfy supply requirements or for entrepreneurial trading. Certain contracts are classified as held for trading, regardless of their original business objective, and are recognized at fair value with changes in fair value recognized in the income statement. Trading activities are undertaken by using a range of contract types in combination to create incremental gains by arbitraging prices between markets, locations and time periods. The net of these exposures is monitored using market value-at-risk techniques
as described in Note 29.
The following tables show further information on the fair value of derivatives and other financial instruments held for trading purposes.
i
Derivative assets held for trading have the following fair values and maturities.
$
million
2020
Less than 1 year
1-2 years
2-3 years
3-4 years
4-5 years
Over 5 years
Total
Currency derivatives
i153
i9
i3
i2
i2
i689
i858
Oil
price derivatives
i1,159
i197
i90
i63
i7
i3
i1,519
Natural
gas price derivatives
i1,210
i731
i596
i525
i476
i2,868
i6,406
Power
price derivatives
i425
i223
i161
i107
i76
i266
i1,258
Other
derivatives
i—
i—
i7
i—
i—
i—
i7
i2,947
i1,160
i857
i697
i561
i3,826
i10,048
$ million
2019
Less
than 1 year
1-2 years
2-3 years
3-4 years
4-5 years
Over 5 years
Total
Currency derivatives
i48
i23
i9
i1
i—
i—
i81
Oil
price derivatives
i1,619
i114
i76
i53
i45
i11
i1,918
Natural
gas price derivatives
i1,889
i824
i615
i489
i433
i2,319
i6,569
Power
price derivatives
i556
i269
i146
i94
i67
i174
i1,306
Other
derivatives
i33
i—
i—
i77
i—
i—
i110
i4,145
i1,230
i846
i714
i545
i2,504
i9,984
/
212
bp
Annual Report and Form 20-F 2020
Financial statements
30. Derivative financial instruments – continued
Derivative liabilities held for trading have the following fair values and maturities.
$
million
2020
Less than 1 year
1-2 years
2-3 years
3-4 years
4-5 years
Over 5 years
Total
Currency derivatives
(i502)
(i117)
(i11)
(i1)
i—
(i63)
(i694)
Oil
price derivatives
(i1,000)
(i83)
(i9)
(i1)
i—
i—
(i1,093)
Natural
gas price derivatives
(i1,095)
(i595)
(i479)
(i422)
(i348)
(i2,550)
(i5,489)
Power
price derivatives
(i345)
(i184)
(i126)
(i81)
(i68)
(i233)
(i1,037)
(i2,942)
(i979)
(i625)
(i505)
(i416)
(i2,846)
(i8,313)
$
million
2019
Less than 1 year
1-2 years
2-3 years
3-4 years
4-5 years
Over 5 years
Total
Currency derivatives
(i166)
(i283)
(i201)
(i1)
(i23)
(i70)
(i744)
Oil
price derivatives
(i1,405)
(i56)
(i14)
(i2)
(i1)
i—
(i1,478)
Natural
gas price derivatives
(i1,070)
(i522)
(i446)
(i399)
(i363)
(i2,071)
(i4,871)
Power
price derivatives
(i395)
(i165)
(i104)
(i76)
(i51)
(i161)
(i952)
(i3,036)
(i1,026)
(i765)
(i478)
(i438)
(i2,302)
(i8,045)
The
following table shows the fair value of derivative assets and derivative liabilities held for trading, analysed by maturity period and by methodology of fair value estimation. This information is presented on a gross basis, that is, before netting by counterparty.
$
million
2020
Less than 1 year
1-2 years
2-3 years
3-4 years
4-5 years
Over 5 years
Total
Fair value of derivative assets
Level
1
i48
i9
i15
i3
i5
i1
i81
Level
2
i3,342
i858
i367
i212
i100
i709
i5,588
Level
3
i739
i546
i552
i520
i493
i3,548
i6,398
i4,129
i1,413
i934
i735
i598
i4,258
i12,067
Less:
netting by counterparty
(i1,182)
(i253)
(i77)
(i38)
(i37)
(i432)
(i2,019)
i2,947
i1,160
i857
i697
i561
i3,826
i10,048
Fair
value of derivative liabilities
Level 1
(i55)
(i9)
(i13)
(i3)
(i5)
(i1)
(i86)
Level
2
(i3,577)
(i809)
(i263)
(i136)
(i41)
(i79)
(i4,905)
Level
3
(i492)
(i414)
(i426)
(i404)
(i407)
(i3,198)
(i5,341)
(i4,124)
(i1,232)
(i702)
(i543)
(i453)
(i3,278)
(i10,332)
Less:
netting by counterparty
i1,182
i253
i77
i38
i37
i432
i2,019
(i2,942)
(i979)
(i625)
(i505)
(i416)
(i2,846)
(i8,313)
Net
fair value
i5
i181
i232
i192
i145
i980
i1,735
$ million
2019
Less than 1 year
1-2
years
2-3 years
3-4 years
4-5 years
Over 5 years
Total
Fair value of derivative assets
Level 1
i63
i6
i2
i—
i2
i1
i74
Level
2
i5,344
i1,014
i439
i210
i120
i42
i7,169
Level
3
i779
i501
i485
i540
i452
i2,708
i5,465
i6,186
i1,521
i926
i750
i574
i2,751
i12,708
Less:
netting by counterparty
(i2,041)
(i291)
(i80)
(i36)
(i29)
(i247)
(i2,724)
i4,145
i1,230
i846
i714
i545
i2,504
i9,984
Fair
value of derivative liabilities
Level 1
(i49)
(i8)
(i4)
(i1)
(i2)
(i1)
(i65)
Level
2
(i4,522)
(i932)
(i458)
(i146)
(i113)
(i101)
(i6,272)
Level
3
(i506)
(i377)
(i383)
(i367)
(i352)
(i2,447)
(i4,432)
(i5,077)
(i1,317)
(i845)
(i514)
(i467)
(i2,549)
(i10,769)
Less:
netting by counterparty
i2,041
i291
i80
i36
i29
i247
i2,724
(i3,036)
(i1,026)
(i765)
(i478)
(i438)
(i2,302)
(i8,045)
Net
fair value
i1,109
i204
i81
i236
i107
i202
i1,939
bp
Annual Report and Form 20-F 2020
213
i
30. Derivative financial instruments – continued
Level 3 derivatives
The following table shows
the changes during the year in the net fair value of derivatives held for trading purposes within level 3 of the fair value hierarchy.
The
amount recognized in the income statement for the year relating to level 3 held-for-trading derivatives still held at 31 December 2020 was a $i315-million gain (2019 $i250-million
gain related to derivatives still held at 31 December 2019).
Derivative gains and losses
The group enters into derivative contracts including futures, options, swaps and certain forward sales and forward purchases contracts, relating to both currency and commodity trading activities. Gains or losses arise on contracts entered into for risk management purposes, optimization activity and entrepreneurial trading. They also arise on certain contracts that are for normal procurement or sales activity for the group but that are
required to be fair valued under accounting standards. These gains and losses are included within sales and other operating revenues in the income statement. Also included within this line item are gains and losses on inventory held for trading purposes. The total amount relating to all these items was a net gain of $i2,808
million. This number does not include gains and losses on the change in value of contracts which are not recognized under IFRS such as transportation and storage contracts, but does include the associated financially settled contracts. The net amounts for actual gains and losses relating to these derivative contracts and all related items therefore differ significantly from the amounts disclosed above.
The group also enters into derivative contracts relating to foreign currency
risk management activities including contracts that the group has entered into to manage the foreign currency exposure relating to the non-US dollar hybrid bonds to their respective first call periods. Gains and losses on these contracts are included within production and manufacturing expenses in the income statement. The change in the unrealized value of these contracts was a net gain of $i829 million
(2019 $i160 million net gain and 2018 $i351
million net loss), however where these gains and losses arise on derivatives hedging finance debt they are largely offset by opposing net foreign exchange differences on retranslation of the associated non-US dollar debt. The net amounts for actual gains and losses relating to these derivative contracts and all related items therefore differ significantly from the amounts disclosed above.
Cash flow hedges
(i) Foreign currency risk of highly probable forecast capital expenditure
At 31 December 2020, the group held currency forwards designated as hedging instruments in cash flow hedge relationships of highly probable forecast non-US dollar capital expenditure. Note 29 outlines the group’s approach to foreign currency exchange risk management. When
the highly probable forecast capital expenditure designated as a hedged item occurs, a non-financial asset is recognized and is presented within the fixed asset section of the balance sheet.
The group claims hedge accounting only for the spot value of the currency exposure in line with the strategy to fix the volatility in the spot exchange rate element. The fair value on the instrument attributable to forward points and foreign currency basis spreads is taken immediately to the income statement.
The group applies hedge accounting where there is an economic relationship between the hedged item and hedging instrument. The existence of an economic relationship is determined at inception and prospectively by comparing the critical terms of the hedging instrument and those of the hedged item. The group enters into hedging derivatives that match the currency and notional of the hedged
items on a 1:1 hedge ratio basis. The hedge ratio is determined by comparing the notional amount of the derivative with the notional designated on the forecast transaction. The group determines the extent to which it hedges highly probable forecast capital expenditures on a project by project basis.
The group has identified the following sources of ineffectiveness, which are not expected to be material:
•counterparty's credit risk, the group mitigates counterparty credit risk by entering into derivative transactions with high credit quality counterparties; and
214
bp
Annual Report and Form 20-F 2020
Financial statements
30. Derivative financial instruments – continued
•differences in settlement timing between the derivative and hedged items. The latter impacts the discount factor used in the calculation of the hedge ineffectiveness. The group mitigates differences in timing between the derivatives and hedged items by applying a rolling strategy and by hedging currency pairs from stable economies (i.e. sterling/US dollar, Korean won/US dollar). The group's
cash flow hedge designations are highly effective as the sources of ineffectiveness identified are expected to result in minimal hedge ineffectiveness.
The group has not designated any net positions as hedged items in cash flow hedges of foreign currency risk.
(ii) Commodity price risk of highly probable forecast sales
During the period the group held Henry Hub NYMEX futures designated as hedging instruments in cash flow hedge relationships of certain highly probable forecast future sales. Henry Hub NYMEX futures are subject to daily settlement, where their fair value at the end of each day is required to be cash settled, such that the carrying amount of these hedging instruments within continuing hedge relationships is always zero at the end of each day.
The group is exposed to the variability
in the gas price, but only applied hedge accounting to the risk of Henry Hub price movements for a percentage of future gas sales from its BPX Energy business.
The group applied hedge accounting in relation to these highly probable future sales where there was an economic relationship between the hedged item and hedging instrument. The existence of an economic relationship was determined at inception and prospectively by comparing the critical terms of the hedging instrument and those of the hedged item. The group entered into hedging derivatives that matched the notional amounts of the hedged items on a 1:1 hedge ratio basis. The hedge ratio was determined by comparing the notional amount of the derivative with the notional amount designated on the forecast transaction.
The hedge was highly effective due to the price index of the hedging instruments matching the price index of the
hedged item. The group did not designate any net positions as hedged items in cash flow hedges of commodity price risk.
i
The tables below summarize the change in the fair value of hedging instruments and the hedged item used to calculate ineffectiveness in the period.
$
million
Change in fair value of hedging instrument used to calculate ineffectiveness
Change in fair value of hedged item used to calculate ineffectiveness
Hedge ineffectiveness recognized in profit or (loss)
At 31 December 2020
Cash flow hedges
Foreign exchange risk
Highly
probable forecast capital expenditure
i4
(i4)
i—
Commodity
price risk
Highly probable forecast sales
i78
(i78)
i—
At
31 December 2019
Cash flow hedges
Foreign exchange risk
Highly probable forecast capital expenditure
(i1)
i1
i—
Commodity
price risk
Highly probable forecast sales
(i100)
i100
i—
The
tables below summarize the carrying amount and nominal amount of the derivatives designated as hedging instruments in cash flow hedge relationships.
Carrying amount of hedging instrument
Nominal amounts
of hedging instruments
Assets
Liabilities
At 31 December 2020
$ million
$ million
$ million
mmBtu
Cash flow hedges
Foreign exchange risk
Highly
probable forecast capital expenditure
i4
i—
i162
Commodity
price risk
Highly probable forecast sales
i—
i—
(i175)
At
31 December 2019
Cash flow hedges
Foreign exchange risk
Highly probable forecast capital expenditure
i1
(i4)
i150
All
hedging instruments are presented within derivative financial instruments on the group balance sheet.
All of the nominal amount of hedging instruments at 31 December 2020 and 2019 relating to highly probably forecast capital expenditure matures within 12 months of the relevant balance sheet date. Of the nominal amount of hedging instruments at 31 December 2020 relating to highly probably forecast sales i135 mmBtu matures within 12 months and i40
mmBtu within one to two years.
/
bp Annual Report and Form 20-F 2020
215
30.
Derivative financial instruments – continued
The table below summarizes the weighted average exchange rates and the weighted average sales price in relation to the derivatives designated as hedging instruments in cash flow hedge relationships at 31 December.
Weighted average price/rate
2020
2019
At
31 December
Forecast capital expenditure
Forecast sales
Forecast capital expenditure
Sterling/US dollar
i1.35
i1.35
Euro/US
dollar
i—
i1.11
Korean
won/US dollar
i1,174.47
i1,115.66
Henry
Hub $/mmBtu
i2.88
Fair value hedges
At 31 December 2020, the group held interest rate and cross-currency interest rate swap contracts
as fair value hedges of the interest rate risk and foreign currency risk arising from group fixed rate debt issuances. Note 29 outlines the group’s approach to interest rate and foreign currency exchange risk management. The interest rate swaps are used to convert US dollar denominated fixed rate borrowings into floating rate debt. The cross-currency interest rate swaps are used to convert sterling, euro, Swiss franc, Canadian dollar and Norwegian krone denominated fixed rate borrowings into US dollar floating rate debt. The group manages all risks derived from debt issuance, such as credit risk, however, the group applies hedge accounting only to certain components of interest rate and foreign currency risk in order to minimize hedge ineffectiveness. The interest rate and foreign currency exposures are identified and hedged on an instrument-by-instrument basis. For interest rate exposures, the group designates as a fair value hedge the benchmark interest rate component
only. This is an observable and reliably measurable component of interest rate risk.
All of the fair value hedge accounting relationships currently in place are directly affected by the interest rate benchmark reform which will replace interbank offered rates (IBORs) with alternative benchmark rates as they all manage interest rate risk. The Group is significantly exposed to benchmark interest rate components; predominantly USD LIBOR, GBP LIBOR, EURIBOR and CHF LIBOR. The nominal amounts of the applicable hedging instruments represent the extent of the risk exposure bp manages for financial derivatives designated in fair value hedge relationships that is directly affected by the interest rate benchmark reform. These are disclosed in the table below. Uncertainty around the method and timing of transition from Inter-bank Offered Rates (IBORs) to alternative risk-free rates (RfRs) may impact the assessment of whether hedge accounting
can be applied to certain hedging relationships. However, the temporary reliefs provided by IFRS 9 allow bp to assume that in the event that significant uncertainty around the reform arises:
•the interest rate benchmark component of fair value hedges only needs to be assessed as separately identifiable at initial designation; and
•the interest rate benchmark is not altered for the purposes of assessing the economic relationship between the hedged item and the hedging instrument for fair value hedges.
Judgement will be required to determine when the uncertainty arising from interest rate benchmark reform is no longer present and when the temporary reliefs no longer apply. However, at 31 December 2020 the reliefs apply and bp continues to monitor regulatory and market developments as it manages
the contractual transition.
For foreign currency exposures, the group excludes from the designation the foreign currency basis spread component implicit in the cross-currency interest rate swaps. This is separately calculated at hedge designation, is recognized in other comprehensive income over the life of the hedge and amortized to the income statement on a straight-line basis, in accordance with the group’s policy on costs of hedging.
The group applies hedge accounting where there is an economic relationship between the hedged item and the hedging instrument. The existence of an economic relationship is determined initially by comparing the critical terms of the hedging instrument and those of the hedged item and it is prospectively assessed using linear regression analysis. The group issues fixed rate debt and enters into interest rate and cross-currency interest rate swaps with
critical terms that match those of the debt and on a 1:1 hedge ratio basis. The hedge ratio is determined by comparing the notional amount of the derivative with the notional amount of the debt. The hedge relationship is designated for the full term and notional value of the debt. Both the hedging instrument and the hedged item are expected to be held to maturity.
The group has identified the following sources of ineffectiveness, which are not expected to be material:
•derivative counterparty’s credit risk which is not offset by the hedged item. This risk is mitigated by entering into derivative transactions only with high credit quality counterparties; and
•sensitivity to interest rate between the hedged item and the derivatives. This is driven by differences in payment frequencies between
the instrument and the bond.
The tables below summarize the change in the fair value of hedging instruments and the hedged item used to calculate ineffectiveness in the period. The signage convention for changes in fair value presented in this table is consistent with that presented in Note 27.
$ million
Change
in fair value of hedging instrument used to calculate ineffectiveness
Change in fair value of hedged item used to calculate ineffectiveness
Hedge ineffectiveness recognized in profit or (loss)
At 31 December 2020
Fair value hedges
Interest rate risk on finance debt
(i258)
i258
i—
Interest
rate and foreign currency risk on finance debt
(i2,743)
i2,549
i194
At
31 December 2019
Fair value hedges
Interest rate risk on finance debt
(i764)
i737
i27
Interest
rate and foreign currency risk on finance debt
(i336)
i286
i50
216
bp
Annual Report and Form 20-F 2020
Financial statements
30. Derivative financial instruments – continued
The tables below summarize the carrying amount of the derivatives designated as hedging instruments in fair value hedge relationships at 31 December.
$
million
Carrying amount of hedging instrument
Nominal amounts of hedging instruments
At 31 December 2020
Assets
Liabilities
Fair value hedges
Interest rate risk on finance debt
i80
i—
i4,104
Interest
rate and foreign currency risk on finance debt
i2,614
(i82)
i23,313
At
31 December 2019
Fair value hedges
Interest rate risk on finance debt
i138
(i35)
i13,442
Interest
rate and foreign currency risk on finance debt
i344
(i637)
i21,296
All
hedging instruments are presented within derivative financial instruments on the group balance sheet. Ineffectiveness arising on fair value hedges is included within the production and manufacturing expenses section of the income statement.
The tables below summarize the profile by tenor of the nominal amount of the derivatives designated as hedging instruments in fair value hedge relationships at 31 December.
$
million
At 31 December 2020
Less than 1 year
1-2 years
2-3 years
3-4 years
4-5 years
5-10 years
Over 10 years
Total
Fair value hedges
Interest
rate risk on finance debt
i2,705
i996
i—
i227
i—
i176
i—
i4,104
Interest
rate and foreign currency risk on finance debt
i737
i1,056
i2,039
i3,175
i2,804
i8,587
i4,915
i23,313
At
31 December 2019
Fair value hedges
Interest rate risk on finance debt
i3,000
i2,576
i4,039
i1,200
i206
i2,421
i—
i13,442
Interest
rate and foreign currency risk on finance debt
i882
i672
i1,400
i2,777
i3,109
i10,216
i2,240
i21,296
The
table below summarizes the weighted average floating interest rate and the weighted average exchange rates in relation to the derivatives designated as hedging instruments in fair value hedge relationships at 31 December.
At 31 December
2020
2019
Interest
rate swaps
Cross-currency interest rate swaps
Interest rate swaps
Cross-currency interest rate swaps
Interest rate
i0.58
%
i1.88
%
i2.36
%
i3.27
%
Sterling/US
dollar
i1.33
i1.32
Euro/US
dollar
i1.14
i1.15
Canadian
dollar/US dollar
i0.78
i0.87
The
tables below summarize the carrying amount, and the accumulated fair value adjustments included within the carrying amount, of the hedged items designated in fair value hedge relationships at 31 December.
$ million
Carrying
amount of hedged item
Accumulated fair value adjustment included in the carrying amount of hedged items
At 31 December 2020
Assets
Liabilities
Assets
Liabilities
Discontinued hedges
Fair value hedges
Interest
rate risk on finance debt
i—
(i4,196)
i—
(i81)
(i775)
Interest
rate and foreign currency risk on finance debt
i—
(i23,253)
i—
(i938)
i—
At
31 December 2019
Fair value hedges
Interest rate risk on finance debt
i—
(i13,441)
i—
(i100)
(i714)
Interest
rate and foreign currency risk on finance debt
i—
(i21,240)
i—
(i525)
i—
The
hedged item for all fair value hedges is presented within finance debt on the group balance sheet.
bp Annual Report and Form 20-F 2020
217
30. Derivative financial instruments – continued
Movement
in reserves related to hedge accounting
The table below provides a reconciliation of the cash flow hedge and costs of hedging reserves on a pre-tax basis by risk category. The signage convention of this table is consistent with that presented in Note 32.
$
million
Cash flow hedge reserve
Costs of hedging reserve
Highly probable forecast capital expenditure
Highly probable forecast sales
Purchase of equitya
Interest rate and foreign currency risk on finance debt
Total
At
1 January 2020
(i1)
i—
(i651)
(i170)
(i822)
Recognized
in other comprehensive income
Cash flow hedges marked to market
i7
i78
i—
—
i85
Cash
flow hedges reclassified to the income statement - hedged item affected profit or loss
i—
(i37)
i—
—
(i37)
Costs
of hedging marked to market
—
—
—
i42
i42
Costs
of hedging reclassified to the income statement
—
—
—
i22
i22
i7
i41
i—
i64
i112
Cash
flow hedges transferred to the balance sheet
i6
i—
i—
—
i6
At
31 December 2020
i12
i41
(i651)
(i106)
(i704)
$
million
Cash flow hedge reserve
Costs of hedging reserve
Highly probable forecast capital expenditure
Highly probable forecast sales
Purchase of equitya
Interest rate and foreign currency risk on finance debt
Total
At
1 January 2019
(i21)
(i6)
(i651)
(i223)
(i901)
Recognized
in other comprehensive income
Cash flow hedges marked to market
(i3)
(i100)
i—
—
(i103)
Cash
flow hedges reclassified to the income statement - hedged item affected profit or loss
i—
i106
i—
—
i106
Costs
of hedging marked to market
—
—
—
(i4)
(i4)
Costs
of hedging reclassified to the income statement
—
—
—
i57
i57
(i3)
i6
i—
i53
i56
Cash
flow hedges transferred to the balance sheet
i23
i—
i—
—
i23
At
31 December 2019
(i1)
i—
(i651)
(i170)
(i822)
a
See Note 32 for further information on the cash flow hedge reserve relating to the purchase of equity.
Substantially all of the cash flow hedge reserve balances and all of the amounts reclassified from the cash flow hedge reserve into profit or loss during the year relate to continuing hedge relationships. Amounts deferred in the cash flow hedge reserve that have been reclassified to profit or loss are presented in sales and other operating revenues in the income statement.
Costs of hedging relates to the foreign currency basis spreads of hedging instruments used to hedge the group's interest rate and foreign currency risk on debt which is a time-period related item.
218
bp
Annual Report and Form 20-F 2020
Financial statements
31.iCalled-up
share capital
i
The allotted, called up and fully paid share capital at 31 December was as follows:
2020
2019
2018
Issued
Shares thousand
$
million
Shares thousand
$ million
Shares thousand
$ million
i8% cumulative first preference shares of £i1
eacha
i7,233
i12
i7,233
i12
i7,233
i12
i9%
cumulative second preference shares of £i1 eacha
i5,473
i9
i5,473
i9
i5,473
i9
i21
i21
i21
Ordinary
shares of i25 cents each
At 1 January
i21,535,840
i5,383
i21,525,464
i5,381
i21,288,193
i5,322
Issue
of new shares for the scrip dividend programme
i—
i—
i208,927
i52
i195,305
i49
Issue
of new shares for employee share-based payment plans
i34,000
i9
i37,400
i9
i92,168
i23
Issue
of new shares – other
i—
i—
i—
i—
i—
i—
Repurchase
of ordinary share capital
(i120,058)
(i30)
(i235,951)
(i59)
(i50,202)
(i13)
At
31 December
i21,449,782
i5,362
i21,535,840
i5,383
i21,525,464
i5,381
i5,383
i5,404
i5,402
a
The nominal amount of i8% cumulative first preference shares and i9%
cumulative second preference shares that can be in issue at any time shall not exceed £i10,000,000 for each class of preference shares.
/
Voting on substantive resolutions tabled at a general meeting is on a poll. On a poll, shareholders present in person or by proxy have itwo
votes for every £5 in nominal amount of the first and second preference shares held and ione vote for every ordinary share held. On a show-of-hands vote on other resolutions (procedural matters) at a general meeting, shareholders present in person or by proxy have one vote each.
In the event of the winding up of the company, preference shareholders would be entitled to a sum equal to the capital paid up on the preference shares, plus an
amount in respect of accrued and unpaid dividends and a premium equal to the higher of (i) i10% of the capital paid up on the preference shares and (ii) the excess of the average market price of such shares on the London Stock Exchange during the previous six months over par value.
During 2020 the company repurchased i120
million ordinary shares for a total consideration of $i776 million, including transaction costs of $i4 million, as part of
the share repurchase programme announced on 31 October 2017. All shares purchased were for cancellation. The repurchased shares represented i0.6% of ordinary share capital. The number of shares in issue is reduced when shares are repurchased.
Treasury sharesa
2020
2019
2018
Shares thousand
Nominal value $
million
Shares thousand
Nominal value $ million
Shares thousand
Nominal value $ million
At 1 January
i1,296,856
i323
i1,426,265
i356
i1,482,072
i370
Purchases
for settlement of employee share plans
i—
i—
i1,118
i—
i757
i—
Issue
of new shares for employee share-based payment plans
i34,116
i9
i37,400
i9
i92,168
i23
Shares
re-issued for employee share-based payment plans
(i143,322)
(i36)
(i167,927)
(i42)
(i148,732)
(i37)
At
31 December
i1,187,650
i296
i1,296,856
i323
i1,426,265
i356
Of
which – shares held in treasury by bp
i1,105,157
i275
i1,163,077
i290
i1,264,732
i316
–
shares held in ESOP trusts
i82,491
i21
i133,707
i33
i161,518
i40
–
shares held by bp’s US share plan administratorb
i2
i—
i72
i—
i15
i—
a See
Note 32 for definition of treasury shares.
b Held in the form of ADSs to meet the requirements of employee share-based payment plans in the US.
For each year presented, the balance at 1 January represents the maximum number of shares held in treasury by bp during the year, representing i5.4% (2019 i5.9%
and 2018 i6.9%) of the called-up ordinary share capital of the company.
During 2020, the movement in shares held in treasury by bp represented less than i0.3%
(2019 less than i0.5% and 2018 less than i1.0%)
of the ordinary share capital of the company.
bp Annual Report and Form 20-F 2020
219
32.Capital and reserves
i
Share capital
Share premium account
Capital redemption reserve
Merger reserve
Total
share capital and capital reserves
At 1 January 2020
i5,404
i12,417
i1,498
i27,206
i46,525
Profit
(loss) for the year
—
—
—
—
—
Items that may be reclassified subsequently to profit or loss
Cash
flow hedges and costs of hedging (including reclassifications)
—
—
—
—
—
Share of items relating to equity-accounted entities, net of taxa
—
—
—
—
—
Other
—
—
—
—
—
Items
that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset
—
—
—
—
—
Cash flow hedges that will subsequently be transferred to the balance sheet
—
—
—
—
—
Total
comprehensive income
—
—
—
—
—
Dividends
i52
(i52)
—
—
i—
Cash
flow hedges transferred to the balance sheet, net of tax
—
—
—
—
—
Repurchases of ordinary share capital
(i59)
—
i59
—
i—
Share-based
payments, net of taxb
i9
i164
—
—
i173
Share
of equity-accounted entities’ changes in equity, net of tax
—
—
—
—
—
Transactions involving non-controlling interests, net of taxe
—
—
—
—
—
At
31 December 2019
i5,404
i12,417
i1,498
i27,206
i46,525
a
Principally foreign exchange effects relating to the Russian rouble.
b Movements in treasury shares relate to employee share-based payment plans.
c Principally relates to a non-controlling interest transaction entered into by Rosneft.
d Principally relates to the sale of interests in our UK and New Zealand retail property portfolio, for which proceeds of $i0.5
billion and $i0.2 billion were received respectively.
e Principally relates to the sale of a i49%
interest in bp's retail property portfolio in Australia.
/
220
bp Annual Report and Form 20-F 2020
Financial
statements
32.Capital and reserves – continued
$
million
Treasury shares
Foreign currency translation reserve
Available- for-sale investments
Cash flow hedges
Costs of hedging
Total fair value reserves
Profit and loss account
bp shareholders’ equity
Non-controlling interests
Total equity
Hybrid
bonds
Other interest
(i14,412)
(i6,495)
—
(i752)
(i160)
(i912)
i73,706
i98,412
—
i2,296
i100,708
—
—
—
—
—
—
(i20,305)
(i20,305)
i256
(i680)
(i20,729)
—
(i2,224)
—
—
—
—
—
(i2,224)
—
i37
(i2,187)
—
—
—
i31
i60
i91
—
i91
—
—
i91
—
—
—
—
—
—
i312
i312
—
—
i312
—
—
—
—
—
—
i71
i71
—
—
i71
—
—
—
—
—
—
i65
i65
—
—
i65
—
—
—
i7
—
i7
—
i7
—
—
i7
—
(i2,224)
—
i38
i60
i98
(i19,857)
(i21,983)
i256
(i643)
(i22,370)
—
—
—
—
—
—
(i6,367)
(i6,367)
—
(i238)
(i6,605)
—
—
—
i6
—
i6
—
i6
—
—
i6
—
—
—
—
—
—
(i776)
(i776)
—
—
(i776)
i1,188
—
—
—
—
—
(i638)
i726
—
—
i726
—
—
—
—
—
—
i1,341
i1,341
—
—
i1,341
—
—
—
—
—
—
(i48)
(i48)
i11,909
—
i11,861
—
—
—
—
—
—
—
—
(i89)
—
(i89)
—
—
—
—
—
—
i3
i3
—
—
i3
—
—
—
—
—
—
(i64)
(i64)
—
i827
i763
(i13,224)
(i8,719)
i—
(i708)
(i100)
(i808)
i47,300
i71,250
i12,076
i2,242
i85,568
(i15,767)
(i8,902)
—
(i777)
(i210)
(i987)
i78,748
i99,444
—
i2,104
i101,548
—
—
—
—
—
—
(i329)
(i329)
—
(i1)
(i330)
(i15,767)
(i8,902)
—
(i777)
(i210)
(i987)
i78,419
i99,115
—
i2,103
i101,218
—
—
—
—
—
—
i4,026
i4,026
—
i164
i4,190
—
i2,407
—
—
—
—
i—
i2,407
—
i9
i2,416
—
—
—
i5
i50
i55
—
i55
—
—
i55
—
—
—
—
—
—
i82
i82
—
—
i82
—
—
—
—
—
—
(i64)
(i64)
—
—
(i64)
—
—
—
—
—
—
i171
i171
—
—
i171
—
—
—
(i3)
—
(i3)
—
(i3)
—
—
(i3)
—
i2,407
i—
i2
i50
i52
i4,215
i6,674
—
i173
i6,847
—
—
—
—
—
—
(i6,929)
(i6,929)
—
(i213)
(i7,142)
—
—
—
i23
—
i23
—
i23
—
—
i23
—
—
—
—
—
—
(i1,511)
(i1,511)
—
—
(i1,511)
i1,355
—
—
—
—
—
(i809)
i719
—
—
i719
—
—
—
—
—
—
i5
i5
—
—
i5
—
—
—
—
—
—
i316
i316
—
i233
i549
(i14,412)
(i6,495)
i—
(i752)
(i160)
(i912)
i73,706
i98,412
—
i2,296
i100,708
bp
Annual Report and Form 20-F 2020
221
32.Capital and reserves – continued
Share capital
Share premium account
Capital redemption reserve
Merger reserve
Total
share capital and capital reserves
At 31 December 2017
i5,343
i12,147
i1,426
i27,206
i46,122
Adjustment
on adoption of IFRS 9, net of tax
—
—
—
—
—
At 1 January 2018
i5,343
i12,147
i1,426
i27,206
i46,122
Profit
(loss) for the year
—
—
—
—
—
Items that may be reclassified subsequently to profit or loss
Cash
flow hedges and costs of hedging (including reclassifications)
—
—
—
—
—
Share of items relating to equity-accounted entities, net of taxa
—
—
—
—
—
Other
—
—
—
—
—
Items
that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset
—
—
—
—
—
Cash flow hedges that will subsequently be transferred to the balance sheet
—
—
—
—
—
Total
comprehensive income
—
—
—
—
—
Dividends
i49
(i49)
—
—
i—
Cash
flow hedges transferred to the balance sheet, net of tax
—
—
—
—
—
Repurchases of ordinary share capital
(i13)
—
i13
—
—
Share-based
payments, net of taxb
i23
i207
—
—
i230
Share
of equity-accounted entities’ changes in equity, net of tax
—
—
—
—
—
Transactions involving non-controlling interests, net of tax
—
—
—
—
—
At
31 December 2018
i5,402
i12,305
i1,439
i27,206
i46,352
a
Principally foreign exchange effects relating to the Russian rouble.
b Movements in treasury shares relate to employee share-based payment plans.
222
bp Annual Report and Form 20-F 2020
Financial
statements
32.Capital and reserves – continued
$
million
Treasury shares
Foreign currency translation reserve
Available- for-sale investments
Cash flow hedges
Costs of hedging
Total fair value reserves
Profit and loss account
bp shareholders’ equity
Non-controlling interests
Total equity
Hybrid
bonds
Other interest
(i16,958)
(i5,156)
i17
(i760)
i—
(i743)
i75,226
i98,491
—
i1,913
i100,404
—
—
(i17)
—
(i37)
(i54)
(i126)
(i180)
—
i—
(i180)
(i16,958)
(i5,156)
i—
(i760)
(i37)
(i797)
i75,100
i98,311
—
i1,913
i100,224
—
—
—
—
—
—
i9,383
i9,383
—
i195
i9,578
—
(i3,746)
—
—
—
—
i—
(i3,746)
—
(i41)
(i3,787)
—
—
—
(i6)
(i173)
(i179)
—
(i179)
—
—
(i179)
—
—
—
—
—
—
i417
i417
—
—
i417
—
—
—
—
—
—
i7
i7
—
—
i7
—
—
—
—
—
—
i1,599
i1,599
—
—
i1,599
—
—
—
(i37)
—
(i37)
—
(i37)
—
—
(i37)
—
(i3,746)
i—
(i43)
(i173)
(i216)
i11,406
i7,444
—
i154
i7,598
—
—
—
—
—
—
(i6,699)
(i6,699)
—
(i170)
(i6,869)
—
—
—
i26
—
i26
—
i26
—
—
i26
—
—
—
—
—
—
(i355)
(i355)
—
—
(i355)
i1,191
—
—
—
—
—
(i718)
i703
—
—
i703
—
—
—
—
—
—
i14
i14
—
—
i14
—
—
—
—
—
—
i—
i—
—
i207
i207
(i15,767)
(i8,902)
i—
(i777)
(i210)
(i987)
i78,748
i99,444
—
i2,104
i101,548
.
bp
Annual Report and Form 20-F 2020
223
32.Capital and reserves – continued
Share capital
The balance on the share capital account represents the aggregate nominal value of all ordinary and preference shares in issue, including treasury shares.
Share premium account
The balance on the share premium account represents the amounts received in excess of the nominal value of the ordinary and preference shares.
Capital redemption reserve
The
balance on the capital redemption reserve represents the aggregate nominal value of all the ordinary shares repurchased and cancelled.
Merger reserve
The balance on the merger reserve represents the fair value of the consideration given in excess of the nominal value of the ordinary shares issued in an acquisition made by the issue of shares.
Treasury shares
Treasury shares represent bp shares repurchased and available for specific and limited purposes. For accounting purposes shares held in Employee Share Ownership Plans (ESOPs) and bp’s US share plan administrator to meet the future requirements of the employee share-based payment plans are treated in the same manner as treasury shares and are, therefore, included in the financial statements as treasury shares. The ESOPs are funded by the group
and have waived their rights to dividends in respect of such shares held for future awards. Until such time as the shares held by the ESOPs vest unconditionally to employees, the amount paid for those shares is shown as a reduction in shareholders’ equity. Assets and liabilities of the ESOPs are recognized as assets and liabilities of the group.
Foreign currency translation reserve
The foreign currency translation reserve records exchange differences arising from the translation of the financial statements of foreign operations. Upon disposal of foreign operations, the related accumulated exchange differences are reclassified to the income statement.
Available-for-sale investments
This reserve recorded the changes in fair value of investments classified as available-for-sale under IAS 39 except
for impairment losses, foreign exchange gains or losses, or changes arising from revised estimates of future cash flows. On adoption of IFRS 9 the balance in this reserve was transferred to the profit and loss account reserve. Under the new standard the group recognizes fair value gains and losses on these investments in profit or loss.
Cash flow hedges
This reserve records the portion of the gain or loss on a hedging instrument in a cash flow hedge that is determined to be an effective hedge. It includes $i651 million relating
to the acquisition of an i18.5% interest in Rosneft in 2013 which will only be reclassified to the income statement if the investment in Rosneft is either sold or impaired. For further information on the accounting for cash flow hedges see Note 1 - Derivative financial instruments and hedging activities.
Costs of hedging
This reserve records the change in fair value of the foreign currency basis spread of financial instruments to which cost of hedge accounting has been applied.
The accumulated amount relates to time-period related hedged items and is amortized to profit or loss over the term of the hedging relationship.
Prior to the group’s adoption of IFRS 9 changes in the fair value of such foreign currency basis spreads were recognized in profit or loss. On adoption of the new standard a transfer from the profit and loss account reserve to the costs of hedging reserve was made in order to reflect the opening reserves position for relevant hedging instruments existing on transition. For further information on the accounting for costs of hedging see Note 1 - Derivative financial instruments and hedging activities.
Profit and loss account
The balance held on this reserve is the accumulated retained profits of the group.
Non-controlling interests
Non-controlling
interests represent the equity in subsidiaries that is not attributable, directly or indirectly, to bp shareholders. Included within non-controlling interests are perpetual subordinated hybrid bonds issued by BP Capital Markets PLC, a group subsidiary, on 17 June 2020 in euro, sterling and US dollars for a US dollar equivalent amount of $i11.9 billion. The hybrid bonds include redemption options exercisable at the
group’s discretion from June 2025 to March 2030 (the first ‘call date’), on specified dates thereafter, or in the event of specific circumstances (such as a change in IFRS or tax regime) as set out in the individual terms of each issue. Coupons are fixed for an initial period up to dates from September 2025 to June 2030 at rates of i3.25% to i4.875%
and reset to rates determined by the contractual terms of each instrument on certain dates thereafter. The contractual terms of the hybrid bonds allow the group to defer coupon payments and the repayment of principal indefinitely, however their terms and conditions stipulate that any deferred payments must be made in the event of an announcement of an ordinary share or parity equity dividend distribution or certain share repurchases or redemptions. As the group has the unconditional right to avoid transferring cash or another financial asset in relation to these hybrid bonds, they are classified as equity instruments and reported within non-controlling interests in the consolidated financial statements.
224
bp
Annual Report and Form 20-F 2020
Financial statements
32. Capital and reserves – continued
i
The
pre-tax amounts of each component of other comprehensive income, and the related amounts of tax, are shown in the table below.
$ million
2020
Pre-tax
Tax
Net of tax
Items
that may be reclassified subsequently to profit or loss
Share
of items relating to equity-accounted entities, net of tax
i417
i—
i417
Other
i—
i7
i7
Items
that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset
i2,317
(i718)
i1,599
Cash
flow hedges that will subsequently be transferred to the balance sheet
(i37)
i—
(i37)
Other
comprehensive income
(i1,266)
(i714)
(i1,980)
/
33.iContingent liabilities and legal proceedings
Contingent liabilities
There were contingent liabilities at 31 December 2020 in respect of guarantees and indemnities entered into as part of the ordinary course of the group’s business. No material losses are likely to arise from such contingent liabilities. Further information on financial
guarantees is included in Note 29.
In the normal course of the group’s business, bp group entities are subject to legal and regulatory proceedings arising out of current and past operations, including matters related to commercial disputes, product liability, antitrust, commodities trading, premises-liability claims, consumer protection, general health, safety, climate change and environmental claims and allegations of exposures of third parties to toxic substances, such as lead pigment in paint, asbestos and other chemicals. The amounts claimed could be significant and could be material to the group’s results of operations, financial position or liquidity. While it is difficult to predict the ultimate outcome in some cases, bp expects that the impact of current legal and regulatory proceedings on the group‘s results of operations, liquidity or financial position will not be material.
The
group files tax returns in many jurisdictions across the world. Various tax authorities are currently examining these returns, which contain matters that could be subject to differing interpretations of applicable tax laws and regulations. The resolution of tax positions through negotiations with relevant tax authorities, or through litigation, can take several years to complete and the amounts could be significant and could, in aggregate, be material to the group’s results of operations, financial position or liquidity. While it is difficult to predict the ultimate outcome in some cases, bp does not expect there to be any material impact upon the group‘s results of operations, financial position or liquidity.
bp
Annual Report and Form 20-F 2020
225
33.Contingent liabilities and legal proceedings – continued
The group is subject to numerous national and local health, safety and environmental laws and regulations concerning its products, operations and other activities. These laws and regulations may require the group to take future action to remediate the effects on the environment of prior disposal or release of chemicals or petroleum substances by the group or other parties. Such contingencies may exist for various sites including refineries, chemical plants, oil fields, commodities extraction sites, service stations, terminals and waste disposal
sites. In addition, the group may have obligations relating to prior asset sales or closed facilities. The ultimate requirement for remediation and its costs are inherently difficult to estimate. However, the estimated cost of environmental obligations has been provided in these accounts in accordance with the group‘s accounting policies. While the amounts of future possible costs that are not provided for could be significant and material to the group‘s results of operations in the period in which they are recognized, it is not possible to estimate the amounts involved. bp does not expect these costs to have a material impact on the group’s results of operations, financial position or liquidity.
If oil and natural gas production facilities and pipelines are sold to third parties and the subsequent owner is unable to meet their decommissioning obligations it is possible that, in certain circumstances, bp could be partially
or wholly responsible for decommissioning. While the amounts associated with decommissioning provisions reverting to the group could be significant and could be material, bp is not currently aware of any such material cases that have a greater than remote chance of reverting to the group. In one current case in the US, the owner of facilities has filed for bankruptcy and submitted a proposed restructuring plan. It is considered possible that certain decommissioning costs associated with some of these facilities may in the future revert to bp in relation to assets previously disposed. No provision has been recognised and no reliable estimate of this potential exposure is available, however any amount which may revert is not expected to have a material impact on the group’s financial position. Furthermore, as described in Provisions and contingencies within Note 1, decommissioning provisions associated with downstream facilities are not generally recognized as the potential
obligations cannot be measured given their indeterminate settlement dates.
Contingent liabilities related to the Gulf of Mexico oil spill
For information on legal proceedings relating to the Deepwater Horizon oil spill, see Legal proceedings below. Any further outstanding Deepwater Horizon related claims are not expected to have a material impact on the group's financial performance.
Legal proceedings
Proceedings relating to the Deepwater Horizon oil spill
Introduction
BP Exploration & Production Inc. (BPXP) was lease operator of Mississippi Canyon, Block 252 in the Gulf of Mexico, where the semi-submersible rig Deepwater Horizon was deployed at the time of the 20 April 2010 explosion and fire and resulting
oil spill (the Incident). Lawsuits and claims arising from the Incident were brought principally in US federal and state courts. The remaining proceedings arising from the Incident are discussed below.
Economic and Property Damages Settlement
On 22 January 2021, the United States District Court for the Eastern District of Louisiana issued an order determining the completion of all claims processing operations of the court supervised settlement programme. That settlement programme had been established to administer claims pursuant to the Economic and Property Damages Settlement (EPD Settlement) which was entered into with the plaintiffs’ steering committee (PSC) acting on behalf of individual and business plaintiffs in the multi-district litigation proceedings in 2012 to resolve certain economic and property damage claims. The Court also ordered that all future issues concerning
EPD Settlement claims would be considered time barred under the settlement programme and that the claims administrator should proceed to complete post-closure administrative wind down activities.
Medical Benefits Class Action Settlement
In 2012 the Medical Benefits Class Action Settlement (Medical Settlement) was entered into with the PSC. It involves payments to qualifying class members based on a matrix for certain Specified Physical Conditions (SPCs), as well as a 21-year Periodic Medical Consultation Program (PMCP) for qualifying class members. As of 31 December 2020, i1
claim remained pending determination. In total, i27,603 claims (comprising i22,833
SPC claims and i4,770 PMCP claims) have been approved for compensation totalling approximately $i67 million
and i9,623 claims have been denied.
The Medical Settlement also includes provisions regarding class members pursuing claims for later-manifested physical conditions (LMPCs). In order to seek compensation from bp for an LMPC, class members must file a notice with the Medical Claims Administrator within i4
years after the date of first diagnosis of the LMPC. As of 31 December 2020, there were i612 pending lawsuits brought by class members claiming LMPCs.
Other civil complaints – economic loss
Nearly all economic loss and property damage claims from individuals and businesses that either opted out of the EPD Settlement and/or were excluded from that settlement have been settled or dismissed.
The claims of i10
US-resident private plaintiffs remain in the multi-district litigation proceedings in federal district court in New Orleans. Those claims have been scheduled for a process of discovery and dispositive motions which is expected to conclude around mid-2021.
Other civil complaints – personal injury
The vast majority of post-explosion clean-up, medical monitoring and personal injury claims from individuals that either opted out of the Medical Settlement and/or were excluded from that settlement have been dismissed.
In 2019, the federal district court in New Orleans determined in a series of proceedings that i923
plaintiffs had post-explosion clean-up, medical monitoring and personal injury claims that complied with the court’s prior order to show cause why their claims should not be dismissed. As a result of several subsequent dismissals, approximately i881 plaintiffs’ claims remained as of 31 December 2020.
On 23 February 2021, the district court issued a Case Management Order announcing its intent to sever the personal injury cases from the multi-district litigation proceedings and staying the litigation of any punitive damages claims until plaintiffs can establish a right to compensatory
damages. The district court also stated that the order severing and re-allotting these cases is forthcoming. Most cases will remain in the federal district court in New Orleans and be re-allotted among the judges of that court.
Individual securities litigation
In October 2020, bp engaged with the plaintiffs in a mediation of all remaining multi-district litigation proceedings in federal district court in Houston. i28 such actions on behalf of i115
plaintiffs remained pending on 31 December 2020. The mediation resulted in settlements of all these cases and settlement agreements have now been executed with all plaintiffs.
226
bp Annual Report and Form 20-F 2020
Financial
statements
33.Contingent liabilities and legal proceedings – continued
Canadian class actions
Following various legal proceedings, a plaintiff seeking to assert claims under Canadian law against bp on behalf of a class of Canadian residents who allegedly suffered losses because of their purchase of bp ordinary shares and ADSs appealed the motion to dismiss the case in its entirety granted on 8 November 2019. On 20 January 2021, the Court of Appeal affirmed that dismissal.
Non-US government lawsuits
On 18 October 2012, before a Mexican Federal District Court located in Mexico City, a class action complaint was filed against BP America Production Company (BPAPC) and other bp subsidiaries.
On 27 June 2018, bp answered the complaint by seeking dismissal on various grounds including that no oil reached Mexican waters or land and there was no economic or environmental harm in Mexico. There has been no material development in these proceedings during 2020 and up to the date of publication of this BP Annual Report and Form 20-F 2020 in 2021.
On 3 December 2015 and 29 March 2016, Acciones Colectivas de Sinaloa (ACS) filed two class actions (which have since been consolidated) in a Mexican Federal District Court on behalf of several Mexican states against BPXP, BPAPC, and other purported bp subsidiaries. In these class actions, plaintiffs seek an order requiring the bp defendants to repair the damage to the Gulf of Mexico, to pay penalties, and to compensate plaintiffs for damage to property, to health and for economic loss.
BPXP and BPAPC opposed class certification and sought dismissal, principally on the basis that no oil reached Mexican waters or land and there was no economic or environmental harm in Mexico. The court certified the class on 25 September 2019 and bp appealed that decision including by way of constitutional challenge (amparo). The amparo action was denied on 8 October 2020 and on 18 January 2021, bp’s appeal of that ruling was also denied. Class notification procedures have not yet been finally determined.
These legal actions remain at a relatively early stage and while it is not possible to predict the outcome, bp believes that it has valid defences, and it intends to defend such actions vigorously.
Other legal proceedings
FERC and CFTC matters
Following an investigation by the US Federal Energy
Regulatory Commission (FERC) and the US Commodity Futures Trading Commission (CFTC) of several bp entities, the Administrative Law Judge of the FERC ruled on 13 August 2015 that bp manipulated the market by selling next-day, fixed price natural gas at Houston Ship Channel in 2008 in order to suppress the Gas Daily index and benefit its financial position. On 11 July 2016 the FERC issued an Order affirming the initial decision and directing bp to pay a civil penalty of $i20.16 million and to disgorge $i207,169
in unjust profits. On 10 August 2016, bp filed a request for rehearing with the FERC. On 17 December 2020, the FERC denied the rehearing request, sustaining the prior decision and ordering payment of the penalty and disgorgement amounts. bp has complied with the order but strongly disagrees with the FERC’s decision and is pursuing an appeal to the US Court of Appeals.
Lead paint matters
Since 1987, Atlantic Richfield Company (Atlantic Richfield), a subsidiary« of bp, has been named as a co-defendant in numerous lawsuits brought in the US alleging injury to persons and property caused by lead pigment in paint. The majority of the lawsuits have been abandoned or dismissed against Atlantic Richfield. Atlantic Richfield is named in these lawsuits as alleged successor to International Smelting and Refining and another company that manufactured
lead pigment during the period 1920-1946. The plaintiffs include individuals and governmental entities. Several of the lawsuits purport to be class actions. The lawsuits seek various remedies including compensation to lead-poisoned children, cost to find and remove lead paint from buildings, medical monitoring and screening programmes, public warning and education of lead hazards, reimbursement of government healthcare costs and special education for lead-poisoned citizens and punitive damages. No lawsuit against Atlantic Richfield has been settled nor has Atlantic Richfield been subject to a final adverse judgment in any proceeding. The amounts claimed and, if such suits were successful, the costs of implementing the remedies sought in the various cases could be substantial. While it is not possible to predict the outcome of these legal actions, Atlantic Richfield believes that it has valid defences. It intends to defend such actions vigorously and believes that the
incurrence of liability is remote. Consequently, bp believes that the impact of these lawsuits on the group’s results, financial position or liquidity will not be material.
Climate change
BP p.l.c., BP America Inc. and BP Products North America Inc. are co-defendants with other oil and gas companies in multiple lawsuits brought in various state and federal courts on behalf of various governmental and private parties. The lawsuits generally assert claims under a variety of legal theories seeking to hold the defendant companies responsible for impacts allegedly caused by and/or relating to climate change and seek remedies including payment of money and other forms of equitable relief. If such suits were successful, the cost of the remedies sought in the various cases could be substantial. All of these lawsuits remain at relatively early stages and while it
is not possible to predict the outcome of these legal actions, BP believes that it has valid defences, and it intends to defend such actions vigorously.
Louisiana Coastal restoration
iSix coastal parishes and the State of Louisiana have filed over i40
separate lawsuits in state courts in Louisiana against various oil and gas companies seeking damages for coastal erosion. bp entities are defendants in i17 of these cases. The lawsuits allege that the defendants' historical operations in oil fields within the Louisiana onshore coastal zone failed to comply with state permits and/or were conducted without the required coastal use permits. The plaintiffs seek unspecified statutory penalties and damages, including the costs of restoring coastal wetlands allegedly impacted by oil field operations.
In
addition, ifour private landowners have filed separate claims in the state courts in Jefferson and Plaquemines Parishes of Louisiana for restoration damages related to alleged impacts to their marshlands associated with historic oil field operations. bp entities are defendants in itwo
of these private landowner cases.
All of these lawsuits remain at relatively early stages and while it is not possible to predict the outcome of these legal actions, bp believes that it has valid defences, and it intends to defend such actions vigorously.
bp Annual Report and Form 20-F 2020
227
34.iRemuneration of senior management and non-executive directors
i
Remuneration
of directors
$ million
2020
2019
2018
Total for all directors
Emoluments
i6
i9
i8
Amounts
received under incentive schemesa
i14
i20
i16
Total
i20
i29
i24
a
Excludes amounts relating to past directors.
/
Emoluments
These amounts comprise fees paid to the non-executive chairman and the non-executive directors and, for executive directors, salary and benefits earned during the relevant financial year, plus cash bonuses awarded for the year.
Pension contributions
During 2020 ione
executive director participated in a UK final salary pension plan in respect of service prior to 1 April 2011. During 2020, ione executive director participated in retirement savings plans established for US employees and in a US defined benefit pension plan in respect of service prior to 1 September 2016.
Further information
Full
details of individual directors’ remuneration are given in the Directors’ remuneration report on page 103. See also Related-party transactions on page 326.
Remuneration of directors and senior management
$ million
2020
2019
2018
Total
for all senior management and non-executive directors
Short-term employee benefits
i17
i30
i25
Pensions
and other post-retirement benefits
i2
i2
i2
Share-based
payments
i52
i32
i32
Termination
benefits
i8
i—
i—
Total
i79
i64
i59
Senior
management comprises members of the leadership team, see pages 78-79 for further information.
Short-term employee benefits
These amounts comprise fees and benefits paid to the non-executive chairman and non-executive directors, as well as salary, benefits and cash bonuses for senior management. Deferred annual bonus awards, to be settled in shares, are included in share-based payments.
Pensions and other post-retirement benefits
The amounts represent the estimated cost to the group of providing pensions and other post-retirement benefits to senior management in respect of the current year of service measured in accordance with IAS 19 ‘Employee Benefits’.
Share-based payments
This is the cost to the group
of senior management’s participation in share-based payment plans, as measured by the fair value of options and shares granted, accounted for in accordance with IFRS 2 ‘Share-based Payments’.
Termination benefits
Termination benefits include compensation to senior management for loss of office.
228
bp Annual Report and Form 20-F 2020
Financial
statements
35.Employee costs and numbers
i
$
million
Employee costs
2020
2019
2018
Wages and salariesa
i7,600
i7,497
i7,931
Social
security costs
i729
i733
i743
Share-based
paymentsb
i728
i694
i669
Pension
and other post-retirement benefit costs
i852
i948
i1,154
i9,909
i9,872
i10,497
2020
2019
2018
Average
number of employeesc
US
Non-US
Total
US
Non-US
Total
US
Non-US
Total
Upstream
i4,800
i10,600
i15,400
i5,800
i11,000
i16,800
i5,900
i11,500
i17,400
Downstreamd
i5,800
i37,800
i43,600
i5,700
i37,300
i43,000
i6,000
i36,300
i42,300
Other
businesses and corporatee
i1,800
i7,300
i9,100
i2,100
i10,600
i12,700
i1,900
i12,100
i14,000
i12,400
i55,700
i68,100
i13,600
i58,900
i72,500
i13,800
i59,900
i73,700
a
Includes termination costs of $i1,237 million (2019 $i182 million and 2018 $i493
million). Reinvent bp restructuring accruals of $i714 million and provisions of $i428 million for employee termination payments were held at 31 December 2020.
b
The group provides certain employees with shares and share options as part of their remuneration packages. The majority of these share-based payment arrangements are equity-settled.
c Reported to the nearest 100.
d Includes i19,100 (2019 i18,100
and 2018 i17,100) service station staff.
e Includes i0 (2019 i2,500
and 2018 i4,000) agricultural, operational and seasonal workers in Brazil.
The reduction in the average number of employees in 2020 compared to 2019 is principally a result of the reinvent bp programme and divestment activity.
a
Fees in respect of the audit of the accounts of BP p.l.c. including the group’s consolidated financial statements.
b Includes interim reviews and audit of internal control over financial reporting and non-statutory audit services. 2020 fees include audit fees relating to the Petrochemicals disposal.
/
With effect from 2018, following a competitive tender process, Deloitte LLP (Deloitte) was appointed as auditor of the Company, replacing Ernst & Young LLP (EY).
2020
includes $i0.5 million of additional fees for 2019. 2019 includes $i3.6
million of additional fees for 2018. In addition to the amounts shown in the table above, in2018 $i0.75 million of additional fees were paid to EY in respect of their audit for 2017. Auditor's remuneration is included in the income statement within distribution and administration expenses.
Tax services (in relation to income tax, indirect tax compliance, employee tax services and tax advisory services) were $nil in all
periods presented.
The audit committee has established pre-approval policies and procedures for the engagement of Deloitte to render audit and certain assurance and other services. The audit fees payable to Deloitte were considered as part of the audit tender process in 2016 and challenged by the audit committee through comparison with the audit pricing proposals of the other bidding firms. Changes in audit fees subsequent to the audit tender, including matters relevant to the 2020 audit, have been reviewed and challenged by the Audit Committee,before being approved. Deloitte performed further assurance services that were not prohibited by regulatory or other professional requirements and were pre-approved by the Committee. Deloitte is engaged for these services when its expertise and experience of bp are important. Most of this work is of an audit-related or assurance nature.
Under SEC regulations, the remuneration of the auditor of $i54 million (2019 $i49 million and 2018 $i42
million) is required to be presented as follows: audit $i41 million (2019 $i43
million and 2018 $i35 million); other audit-related $i11
million (2019 $i4 million and 2018 $i4
million); tax $inil (2019 $inil
and 2018 $inil); and all other fees $i2
million (2019 $i2 million and 2018 $i3
million).
bp Annual Report and Form 20-F 2020
229
37.iSubsidiaries,
joint arrangements and associates
i
The more important subsidiaries and associates of the group at 31 December 2020 and the group percentage of ordinary share capital (to nearest whole number) are set out below. There are no individually significant incorporated joint arrangements. The group's share of the assets and liabilities of the more important unincorporated joint arrangements
are held by subsidiaries listed in the table below. Those subsidiaries held directly by the parent company are marked with an asterisk (*), the percentage owned being that of the group unless otherwise indicated. A complete list of undertakings of the group is included in Note 14 in the parent company financial statements of BP p.l.c. which are filed with the Registrar of Companies in the UK, along with the group’s annual report.
Exploration
and production, refining and marketing
BP America
i100
US
BP America Production Company
i100
US
BP
Company North America
i100
US
BP Corporation North America
i100
US
BP
Products North America
i100
US
Standard Oil Company
i100
US
BP
Capital Markets America
i100
US
Finance
Associates
%
Country
of incorporation
Principal activities
Russia
Rosneft Oil Company
i19.75
Russia
Integrated
oil operations
/
38.iCondensed consolidating information on certain
US subsidiaries
On June 30, 2020, bp completed the sale of all its interest in BP Exploration (Alaska) Inc., to Hilcorp Energy, and BP Exploration (Alaska) Inc. is therefore no longer a subsidiary of BP p.l.c. Accordingly, bp is no longer presenting condensed consolidating information on BP Exploration (Alaska) Inc. as a subsidiary issuer of registered securities pursuant to Rule 3-10 of Regulation S-X. BP p.l.c. will continue to fully and unconditionally guarantee the payment obligations under the BP Prudhoe Bay Royalty Trust. BP p.l.c. also fully and unconditionally guarantees securities issued by BP Capital Markets p.l.c. and BP Capital Markets America Inc., which are 100%-owned finance subsidiaries
of BP p.l.c.
230
bp Annual Report and Form 20-F 2020
Financial
statements
Supplementary information on oil and natural gas (unaudited)
The regional analysis presented below is on a continent basis, with separate disclosure for countries that contain 15% or more of the total proved reserves (for subsidiaries plus equity-accounted entities), in accordance with SEC and FASB requirements.
Oil and gas reserves – certain definitions
Unless the context indicates otherwise, the following terms have the meanings shown below:
Proved oil and gas reserves
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering
data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i)The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any; and
(B)
Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
(ii)In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii)Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish
the higher contact with reasonable certainty.
(iv)Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favourable than in the reservoir as a whole, the operation of an installed programme in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or programme was based; and
(B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v)Existing
economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Undeveloped oil and gas reserves
Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
(i)Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas
that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii)Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
(iii)Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
Developed
oil and gas reserves
Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i)Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii)Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
For details on bp’s proved reserves and production compliance and governance processes, see pages 312-317.
bp
Annual Report and Form 20-F 2020
231
Oil and natural gas exploration and production activities
Total
replacement cost profit (loss) before interest and tax
(3,220)
69
(5,167)
(3,643)
(5,475)
(4,826)
(277)
564
279
(21,696)
a
These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries, which includes bp's share of oil and natural gas exploration and production activities of joint operations. They do not include any costs relating to the Gulf of Mexico oil spill. Amounts relating to the management and ownership of crude oil and natural gas pipelines, LNG liquefaction and transportation operations are excluded. In addition, bp's midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK, Asia and Europe are excluded. The most significant midstream pipeline interests include the South Caucasus Pipeline, the Baku-Tbilisi-Ceyhan pipeline, the Trans Adriatic Pipeline and the Trans Anatolian Pipeline. Major LNG activities are located in Trinidad, Indonesia and Australia.
b
Costs of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
c Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred.
d Presented net of transportation costs, purchases and sales taxes.
e Includes property taxes and other government take. The UK region includes a $330-million gain which is offset by corresponding charges primarily in the US region, relating to the group self-insurance programme.
f Excludes the unwinding of the discount on provisions and payables amounting to $369 million which
is included in finance costs in the group income statement.
g Midstream and other activities excludes inventory holding gains and losses.
h The profits of equity-accounted entities are included after interest and tax.
232
bp
Annual Report and Form 20-F 2020
Financial statements
Oil and natural gas exploration and production activities – continued
$
million
2020
Europe
North America
South America
Africa
Asia
Australasia
Total
UK
Rest
of Europe
US
Rest of North America
Russiaa
Rest of Asia
Equity-accounted entities (bp share)
Capitalized costs at 31 Decemberb c
Gross
capitalized costs
Proved properties
—
4,457
—
—
10,690
—
24,963
—
—
40,110
Unproved
properties
—
806
—
—
108
—
4,627
—
—
5,541
—
5,263
—
—
10,798
—
29,590
—
—
45,651
Accumulated
depreciation
—
1,592
—
—
5,490
—
7,693
—
—
14,775
Net
capitalized costs
—
3,671
—
—
5,308
—
21,897
—
—
30,876
Costs
incurred for the year ended 31 Decemberb d e
Acquisition of propertiesc
Proved
—
—
—
—
—
—
82
—
—
82
Unproved
—
—
—
—
—
—
3,714
—
—
3,714
—
—
—
—
—
—
3,796
—
—
3,796
Exploration
and appraisal costsd
—
46
—
—
15
—
315
—
—
376
Development
—
404
—
—
393
—
2,594
—
—
3,391
Total
costs
—
450
—
—
408
—
6,705
—
—
7,563
Results
of operations for the year ended 31 Decemberb
Sales and other operating revenuesf
Third parties
—
860
—
—
1,110
—
—
—
—
1,970
Sales
between businesses
—
—
—
—
—
—
9,344
—
—
9,344
—
860
—
—
1,110
—
9,344
—
—
11,314
Exploration
expenditure
—
50
—
—
—
—
109
—
—
159
Production
costs
—
188
—
—
486
—
1,387
—
—
2,061
Production
taxes
—
—
—
—
216
—
4,418
—
—
4,634
Other
costs (income)
—
3
—
—
5
—
236
—
—
244
Depreciation,
depletion and amortization
—
412
—
—
411
—
1,532
—
—
2,355
Net
impairments and losses on sale of businesses and fixed assets
119
—
—
108
—
294
—
—
521
—
772
—
—
1,226
—
7,976
—
—
9,974
Profit
(loss) before taxation
—
88
—
—
(116)
—
1,368
—
—
1,340
Allocable
taxes
—
15
—
—
(41)
—
226
—
—
200
Results
of operations
—
73
—
—
(75)
—
1,142
—
—
1,140
Upstream
and Rosneft segments replacement cost profit (loss) before interest and tax from equity-accounted entities
Exploration and production activities – equity-accounted entities after tax (as above)
—
73
—
—
(75)
—
1,142
—
—
1,140
Midstream
and other activities after taxg
—
(42)
17
—
(136)
(242)
(1,366)
224
—
(1,545)
Total
replacement cost profit (loss) after interest and tax
—
31
17
—
(211)
(242)
(224)
224
—
(405)
a
Amounts reported for Russia in this table include bp’s share of Rosneft’s worldwide activities, including insignificant amounts outside Russia.
b These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. Amounts relating to the management and ownership of crude oil and natural gas pipelines, LNG liquefaction, transportation operations as well as downstream and other activities are excluded.
c Costs of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
d Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged
to income as incurred.
e The amounts shown reflect bp’s share of equity-accounted entities’ costs incurred, and not the costs incurred by bp in acquiring an interest in equity-accounted entities.
f Presented net of sales tax.
g Includes interest and adjustment for non-controlling interests. Excludes inventory holding gains and losses.
bp
Annual Report and Form 20-F 2020
233
Oil and natural gas exploration and production activities – continued
Total replacement cost profit (loss) after interest and tax
1,070
54
(3,774)
402
(141)
357
2,427
5,803
1,035
7,233
a
These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries, which includes bp's share of oil and natural gas exploration and production activities of joint operations. They do not include any costs relating to the Gulf of Mexico oil spill. Amounts relating to the management and ownership of crude oil and natural gas pipelines, LNG liquefaction and transportation operations are excluded. In addition, bp's midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK, Asia and Europe are excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline System, the South Caucasus Pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major LNG activities are located in Trinidad, Indonesia and Australia.
b
Costs of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
c Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred.
d Presented net of transportation costs, purchases and sales taxes.
e Includes property taxes and other government take. The UK region includes a $361-million gain which is offset by corresponding charges primarily in the US region, relating to the group self-insurance programme.
f Excludes the unwinding of the discount on provisions and payables amounting to $439 million which
is included in finance costs in the group income statement.
g Midstream and other activities excludes inventory holding gains and losses.
h The profits of equity-accounted entities are included after interest and tax.
234
bp Annual Report and Form 20-F 2020
Financial
statements
Oil and natural gas exploration and production activities – continued
$
million
2019
Europe
North America
South America
Africa
Asia
Australasia
Total
UK
Rest
of Europe
US
Rest of North America
Russiaa
Rest of Asia
Equity-accounted entities (bp share)
Capitalized costs at 31 Decemberb c
Gross
capitalized costs
Proved properties
—
4,078
—
—
10,376
—
28,179
—
—
42,633
Unproved
properties
—
768
—
—
93
—
1,097
—
—
1,958
—
4,846
—
—
10,469
—
29,276
—
—
44,591
Accumulated
depreciation
—
1,046
—
—
5,078
—
8,477
—
—
14,601
Net capitalized costs
—
3,800
—
—
5,391
—
20,799
—
—
29,990
Costs
incurred for the year ended 31 Decemberb d e
Acquisition of propertiesc
Proved
—
—
—
—
—
—
—
—
—
—
Unproved
—
—
—
—
—
—
58
—
—
58
—
—
—
—
—
—
58
—
—
58
Exploration
and appraisal costsd
—
120
—
—
19
—
177
—
—
316
Development
—
640
—
—
675
—
2,908
—
—
4,223
Total
costs
—
760
—
—
694
—
3,143
—
—
4,597
Results
of operations for the year ended 31 Decemberb
Sales and other operating revenuesf
Third parties
—
1,002
—
—
1,621
—
—
—
—
2,623
Sales
between businesses
—
—
—
—
—
—
15,012
—
—
15,012
—
1,002
—
—
1,621
—
15,012
—
—
17,635
Exploration
expenditure
—
92
—
—
43
—
73
—
—
208
Production costs
—
216
—
—
465
—
1,386
—
—
2,067
Production
taxes
—
—
—
—
343
—
7,413
—
—
7,756
Other costs (income)
—
59
—
—
16
—
346
—
—
421
Depreciation,
depletion and amortization
—
323
—
—
414
—
1,657
—
—
2,394
Net impairments and losses on sale of businesses and fixed assets
—
—
—
—
(42)
—
46
—
—
4
—
690
—
—
1,239
—
10,921
—
—
12,850
Profit
(loss) before taxation
—
312
—
—
382
—
4,091
—
—
4,785
Allocable taxes
—
229
—
—
245
—
811
—
—
1,285
Results
of operations
—
83
—
—
137
—
3,280
—
—
3,500
Upstream
and Rosneft segments replacement cost profit (loss) before interest and tax from equity-accounted entities
Exploration and production activities – equity-accounted entities after tax (as above)
—
83
—
—
137
—
3,280
—
—
3,500
Midstream
and other activities after taxg
(6)
(13)
23
—
(72)
82
(820)
213
—
(593)
Total replacement cost profit (loss) after interest and tax
(6)
70
23
—
65
82
2,460
213
—
2,907
a
Amounts reported for Russia in this table include bp’s share of Rosneft’s worldwide activities, including insignificant amounts outside Russia. Amounts reported have been amended to exclude the corresponding amounts for their equity-accounted entities.
b These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. Amounts relating to the management and ownership of crude oil and natural gas pipelines, LNG liquefaction, transportation operations as well as downstream and other activities are excluded.
c Costs of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
d Includes exploration and appraisal drilling expenditures, which are
capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred.
e The amounts shown reflect bp’s share of equity-accounted entities’ costs incurred, and not the costs incurred by bp in acquiring an interest in equity-accounted entities.
f Presented net of sales tax.
g Includes interest and adjustment for non-controlling interests. Excludes inventory holding gains and losses.
bp
Annual Report and Form 20-F 2020
235
Oil and natural gas exploration and production activities – continued
Total replacement cost profit (loss)
after interest and tax
1,728
397
3,068
(425)
386
2,207
2,304
5,670
1,214
16,549
a These tables contain information relating to oil and natural
gas exploration and production activities of subsidiaries, which includes bp's share of oil and natural gas exploration and production activities of joint operations. They do not include any costs relating to the Gulf of Mexico oil spill. Amounts relating to the management and ownership of crude oil and natural gas pipelines, LNG liquefaction and transportation operations are excluded. In addition, bp's midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK, Asia and Europe are excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline System, the South Caucasus Pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major LNG activities are located in Trinidad, Indonesia and Australia.
b Costs of decommissioning are included in capitalized
costs at 31 December but are excluded from costs incurred for the year.
c Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred.
d Presented net of transportation costs, purchases and sales taxes.
e Includes property taxes, other government take and the fair value gain on embedded derivatives of $17 million. The UK region includes a $384-million gain which is offset by corresponding charges primarily in the US region, relating to the group self-insurance programme.
f Excludes the unwinding of the discount on provisions and payables amounting to $208 million
which is included in finance costs in the group income statement.
g US region includes the deferred tax impact of the reduction in the US Federal corporate income tax rate from 35% to 21% enacted in December 2017.
h Midstream and other activities excludes inventory holding gains and losses.
i The profits of equity-accounted entities are included after interest and taxes.
j From 16 December 2017, bp entered into a new 50:50 joint venture Pan American Energy Group (PAEG). Prior to this, Pan American Energy (PAE) was owned 60% by bp and 40% by Bridas Corporation.
236
bp
Annual Report and Form 20-F 2020
Financial statements
Oil and natural gas exploration and production activities – continued
$
million
2018
Europe
North America
South America
Africa
Asia
Australasia
Total
UK
Rest
of Europe
US
Rest of North America
Russiaa
Rest of Asia
Equity-accounted entities (bp share)
Capitalized costs at 31 Decemberb c
Gross
capitalized costs
Proved properties
—
3,439
—
—
9,643
—
22,561
3,646
—
39,289
Unproved
properties
—
657
—
—
86
—
811
26
—
1,580
—
4,096
—
—
9,729
—
23,372
3,672
—
40,869
Accumulated
depreciation
—
670
—
—
4,665
—
6,050
3,672
—
15,057
Net capitalized costs
—
3,426
—
—
5,064
—
17,322
—
—
25,812
Costs
incurred for the year ended 31 Decemberb d e
Acquisition of propertiesc
Proved
—
—
—
—
—
—
393
—
—
393
Unproved
—
137
—
—
—
—
148
—
—
285
—
137
—
—
—
—
541
—
—
678
Exploration
and appraisal costsd
—
67
—
—
25
—
179
—
—
271
Development
—
251
—
—
575
—
3,085
212
—
4,123
Total
costs
—
455
—
—
600
—
3,805
212
—
5,072
Results
of operations for the year ended 31 Decemberb
Sales and other operating revenuesf
Third parties
—
1,114
—
—
1,792
—
—
353
—
3,259
Sales
between businesses
—
—
—
—
—
—
14,839
—
—
14,839
—
1,114
—
—
1,792
—
14,839
353
—
18,098
Exploration
expenditure
—
89
—
—
7
—
109
—
—
205
Production costs
—
207
—
—
438
—
1,324
39
—
2,008
Production
taxes
—
—
—
—
361
—
7,168
94
—
7,623
Other costs (income)
—
21
—
—
55
—
594
—
—
670
Depreciation,
depletion and amortization
—
290
—
—
416
—
1,514
212
—
2,432
Net impairments and losses on sale of businesses and fixed assets
—
6
—
—
—
—
47
1
—
54
—
613
—
—
1,277
—
10,756
346
—
12,992
Profit
(loss) before taxation
—
501
—
—
515
—
4,083
7
—
5,106
Allocable taxes
—
350
—
—
321
—
814
—
—
1,485
Results
of operationsg
—
151
—
—
194
—
3,269
7
—
3,621
Upstream
and Rosneft segments replacement cost profit (loss) before interest and tax from equity-accounted entities
Exploration and production activities – equity-accounted entities after tax (as above)
—
151
—
—
194
—
3,269
7
—
3,621
Midstream
and other activities after taxh
(2)
(21)
28
—
15
207
(923)
238
—
(458)
Total replacement cost profit (loss) after interest and tax
(2)
130
28
—
209
207
2,346
245
—
3,163
a
Amounts reported for Russia in this table include bp’s share of Rosneft’s worldwide activities, including insignificant amounts outside Russia. The amounts reported have been amended to exclude the corresponding amounts for their equity-accounted entities.
b These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. Amounts relating to the management and ownership of crude oil and natural gas pipelines, LNG liquefaction, transportation operations as well as downstream and other activities are excluded.
c Costs of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
d Includes exploration and appraisal drilling expenditures, which
are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred.
e The amounts shown reflect bp’s share of equity-accounted entities’ costs incurred, and not the costs incurred by bp in acquiring an interest in equity-accounted entities.
f Presented net of sales taxes.
g From 16 December 2017, bp entered into a new 50:50 joint venture Pan American Energy Group (PAEG). Prior to this, Pan American Energy (PAE) was owned 60% by bp and 40% by Bridas Corporation.
h Includes interest and adjustment for non-controlling interests. Excludes inventory holding gains and losses.
Total
subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
206
115
1,063
40
298
158
3,159
1,074
26
6,140
Undeveloped
200
35
842
198
262
40
2,535
525
4
4,642
406
150
1,905
238
560
198
5,695
1,599
30
10,781
At
31 December
Developed
162
112
697
42
283
119
3,123
1,100
34
5,671
Undeveloped
148
24
742
215
246
22
2,493
548
5
4,441
309
136
1,438
258
529
140
5,615
1,648
38
10,112
a
Crude oil includes condensate and bitumen. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Includes 37 million barrels of crude oil associated with Assets Held for Sale in Oman.
d Includes 5 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
f
Includes 393 million barrels of crude oil in respect of the 7.09% non-controlling interest in Rosneft, including 18.53 mmbbl held through bp's interests in Russia other than Rosneft.
g Total proved crude oil reserves held as part of our equity interest in Rosneft is 5,533 million barrels, comprising less than 1 million barrels each in Egypt, Vietnam, Iraq and Canada, 0 million barrels in Venezuela and 5,531 million barrels in Russia.
238
bp
Annual Report and Form 20-F 2020
Financial statements
Movements in estimated net proved reserves – continued
Total
subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
8
5
229
—
4
23
89
—
4
363
Undeveloped
5
3
250
—
21
4
52
—
—
334
13
7
479
—
25
27
141
—
4
697
At
31 December
Developed
7
6
115
—
4
25
108
—
2
268
Undeveloped
—
1
218
—
19
1
43
—
—
281
7
7
333
—
23
26
151
—
2
549
a
Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Includes 0 million barrels of NGL associated with Assets Held for Sale in Oman.
d Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities.
e Includes
6 million barrels of NGL in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
g Includes 12 million barrels of NGLs in respect of the 7.99% non-controlling interest in Rosneft.
h Total proved NGL reserves held as part of our equity interest in Rosneft is 151 million barrels, comprising less than 1 million barrels each in Egypt, Venezuela, Vietnam and Canada, and 151 million barrels in Russia.
bp
Annual Report and Form 20-F 2020
239
Movements in estimated net proved reserves – continued
Total
subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
214
120
1,292
40
302
181
3,248
1,074
30
6,502
Undeveloped
205
37
1,092
198
283
43
2,588
525
4
4,976
420
157
2,384
238
585
224
5,836
1,599
34
11,478
At
31 December
Developed
168
118
812
42
287
144
3,231
1,100
36
5,938
Undeveloped
148
25
959
215
265
23
2,535
548
5
4,722
316
143
1,771
258
552
166
5,766
1,648
41
10,661
a
Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Includes 37 million barrels associated with Assets Held for Sale in Oman.
d Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities.
e Also includes
11 million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
g Includes 405 million barrels of liquids in respect of the non-controlling interest in Rosneft, including 19mmboe held through bp’s interests in Russia other than Rosneft.
h Total proved liquid reserves held as part of our equity interest in Rosneft is 5,683 million barrels, comprising 0 million barrels in Venezuela, less than 1 million barrels each in Iraq, Canada, Egypt and Vietnam and 5,682 million barrels in Russia.
240
bp
Annual Report and Form 20-F 2020
Financial statements
Movements in estimated net proved reserves – continued
Total
subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
493
108
6,330
—
3,323
1,670
9,324
3,677
2,256
27,181
Undeveloped
207
56
2,127
6
2,682
742
8,067
3,401
1,132
18,421
700
164
8,458
6
6,004
2,413
17,391
7,078
3,389
45,601
At
31 December
Developed
306
141
1,921
2
2,532
1,982
11,373
3,890
2,058
24,206
Undeveloped
51
21
3,423
6
2,477
300
7,312
3,641
1,029
18,260
358
162
5,344
8
5,009
2,282
18,685
7,531
3,087
42,467
a
Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Includes 1316 billion cubic feet of natural gas associated with Assets Held for Sale in Oman.
d Includes 158 billion cubic feet of natural gas consumed in operations, 103 billion cubic feet in subsidiaries, 55 billion cubic feet in equity-accounted entities.
e Includes 1,059
billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
g Includes 1,640 billion cubic feet of natural gas in respect of the 10.01% non-controlling interest in Rosneft including 614 billion cubic feet held through bp’s interests in Russia other than Rosneft.
h Total proved gas reserves held as part of our equity interest in Rosneft is 16,324 billion cubic feet, comprising 0 billion cubic feet in Venezuela, 7 billion cubic feet in Vietnam, 420 billion cubic feet in Egypt and 15,897 billion cubic feet in Russia.
bp
Annual Report and Form 20-F 2020
241
Movements in estimated net proved reserves – continued
Total
subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
300
139
2,384
40
875
469
4,856
1,708
419
11,189
Undeveloped
241
47
1,459
199
746
171
3,978
1,112
199
8,152
540
186
3,842
239
1,621
640
8,834
2,820
618
19,341
At
31 December
Developed
221
142
1,143
43
724
485
5,192
1,771
391
10,112
Undeveloped
157
29
1,549
217
692
74
3,796
1,175
182
7,871
378
171
2,692
259
1,415
560
8,988
2,946
573
17,982
a
Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c 5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent.
d Includes 264 million barrels of oil equivalent associated with Assets Held for Sale in Oman.
e Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries
and 3 thousand barrels per day for equity-accounted entities.
f Includes 27 million barrels of oil equivalent of natural gas consumed in operations, 18 million barrels of oil equivalent in subsidiaries, 10 million barrels of oil equivalent in equity-accounted entities.
g Includes 194 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
h Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
i Includes 687 million barrels of oil equivalent in respect of the non-controlling interest in Rosneft, including 124mmboe
held through bp’s interests in Russia other than Rosneft.
j Total proved reserves held as part of our equity interest in Rosneft is 8,498 million barrels of oil equivalent, comprising less than 1 million barrels of oil equivalent in Iraq and Canada, 0 million barrels of oil equivalent in Venezuela, 1 million barrels of oil equivalent in Vietnam, 73 million barrels of oil equivalent in Egypt and 8,423 million barrels of oil equivalent in Russia.
242
bp
Annual Report and Form 20-F 2020
Financial statements
Movements in estimated net proved reserves – continued
Total
subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
223
57
962
43
302
224
3,190
1,126
30
6,156
Undeveloped
243
100
802
209
264
36
2,414
482
5
4,555
466
157
1,764
253
566
260
5,604
1,608
34
10,711
At
31 December
Developed
206
115
1,063
40
298
158
3,159
1,074
26
6,140
Undeveloped
200
35
842
198
262
40
2,535
525
4
4,642
406
150
1,905
238
560
198
5,695
1,599
30
10,781
a
Crude oil includes condensate and bitumen. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 4.5 million barrels upon which a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust.
d Includes 362 million barrels of crude oil associated with Assets Held for Sale in the USA.
e Includes
4 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
g Includes 346 million barrels of crude oil in respect of the 6.17% non-controlling interest in Rosneft, including 26 mmbbl held through bp’s interests in Russia other than Rosneft.
h Total proved crude oil reserves held as part of our equity interest in Rosneft is 5,604 million barrels, comprising less than 1 million barrels in Egypt, Vietnam, Iraq and Canada, 35 million barrels in Venezuela and 5,568 million barrels in Russia.
bp
Annual Report and Form 20-F 2020
243
Movements in estimated net proved reserves – continued
Total
subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
8
4
266
—
2
22
103
—
5
409
Undeveloped
6
3
246
—
25
4
51
—
—
335
14
7
511
—
27
26
154
—
5
744
At
31 December
Developed
8
5
229
—
4
23
89
—
4
363
Undeveloped
5
3
250
—
21
4
52
—
—
334
13
7
479
—
25
27
141
—
4
697
a
Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Includes 94 million barrels of NGL associated with Assets Held for Sale in the USA.
d Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities.
e Includes
7 million barrels of NGL in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
g Includes 11 million barrels of NGLs in respect of the 7.90% non-controlling interest in Rosneft.
h Total proved NGL reserves held as part of our equity interest in Rosneft is 141 million barrels, comprising less than 1 million barrels in Egypt, Venezuela, Vietnam and Canada, and 141 million barrels in Russia.
244
bp
Annual Report and Form 20-F 2020
Financial statements
Movements in estimated net proved reserves – continued
Total
subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
231
60
1,228
44
303
245
3,293
1,126
35
6,565
Undeveloped
249
104
1,048
209
289
40
2,465
482
5
4,890
480
164
2,276
253
593
285
5,758
1,608
39
11,456
At
31 December
Developed
214
120
1,292
40
302
181
3,248
1,074
30
6,502
Undeveloped
205
37
1,092
198
283
43
2,588
525
4
4,976
420
157
2,384
238
585
224
5,836
1,599
34
11,478
a
Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 4.5 million barrels of oil equivalent upon which a net profits royalty will be payable, over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust.
d Includes 456 million barrels associated with Assets Held for Sale in the USA.
e Excludes NGLs from processing plants in which
an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities.
f Also includes 11 million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
g Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
h Includes 357 million barrels in respect of the non-controlling interest in Rosneft, including 26 mmboe held through bp’s interests in Russia other than Rosneft.
i Total proved liquid reserves held as part of our equity interest in Rosneft is 5,745 million
barrels, comprising 35 million barrels in Venezuela, less than 1 million barrels in Iraq, Canada, Egypt and Vietnam and 5,709 million barrels in Russia.
bp Annual Report and Form 20-F 2020
245
Movements in estimated net proved reserves – continued
Total
subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
439
107
6,270
—
3,375
1,704
7,798
3,610
2,630
25,934
Undeveloped
343
55
5,056
4
3,519
1,210
8,719
3,221
1,179
23,305
782
161
11,326
4
6,894
2,914
16,517
6,832
3,809
49,239
At
31 December
Developed
493
108
6,330
—
3,323
1,670
9,324
3,677
2,256
27,181
Undeveloped
207
56
2,127
6
2,682
742
8,067
3,401
1,132
18,421
700
164
8,458
6
6,004
2,412
17,391
7,078
3,389
45,601
a
Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Includes 3,054 billion cubic feet of natural gas associated with Assets Held for Sale in the USA.
d Includes 188 billion cubic feet of natural gas consumed in operations, 146 billion cubic feet in subsidiaries, 42 billion cubic feet in equity-accounted entities.
e Includes 1,330
billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
g Includes 1,433 billion cubic feet of natural gas in respect of the 9.72% non-controlling interest in Rosneft including 569 billion cubic feet held through bp’s interests in Russia other than Rosneft.
h Total proved gas reserves held as part of our equity interest in Rosneft is 14,705 billion cubic feet, comprising 28 billion cubic feet in Venezuela, 10 billion cubic feet in Vietnam, 171 billion cubic feet in Egypt and 14,495 billion cubic feet in Russia.
246
bp
Annual Report and Form 20-F 2020
Financial statements
Movements in estimated net proved reserves – continued
Total
subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
307
79
2,309
44
885
539
4,638
1,749
488
11,037
Undeveloped
308
113
1,919
210
896
249
3,968
1,037
208
8,908
615
192
4,228
253
1,781
788
8,605
2,786
696
19,945
At
31 December
Developed
300
139
2,384
40
875
469
4,856
1,708
419
11,189
Undeveloped
241
47
1,459
199
746
171
3,978
1,112
199
8,152
540
186
3,842
239
1,621
640
8,834
2,820
618
19,341
a
Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c 5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent.
d Proved reserves in the Prudhoe Bay field in Alaska include an estimated 4.5 million barrels of oil equivalent upon which a net profits royalty will be payable, over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust.
e Includes 982 million barrels of oil equivalent
associated with Assets Held for Sale in the USA.
f Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities.
g Includes 32 million barrels of oil equivalent of natural gas consumed in operations, 25 million barrels of oil equivalent in subsidiaries, 7 million barrels of oil equivalent in equity-accounted entities.
h Includes 240 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
i
Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
j Includes 603 million barrels of oil equivalent in respect of the non-controlling interest in Rosneft, including 124 mmboe held through bp’s interests in Russia other than Rosneft.
k Total proved reserves held as part of our equity interest in Rosneft is 8,281 million barrels of oil equivalent, comprising less than 1 million barrels of oil equivalent in Iraq and Canada, 40 million barrels of oil equivalent in Venezuela, 2 million barrels of oil equivalent in Vietnam, 30 million barrels of oil equivalent in Egypt and 8,208 million barrels of oil equivalent in Russia.
bp
Annual Report and Form 20-F 2020
247
Movements in estimated net proved reserves – continued
Total
subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
245
56
932
54
295
282
3,124
1,047
31
6,064
Undeveloped
164
89
492
195
269
28
2,251
642
11
4,140
409
145
1,423
249
564
310
5,374
1,688
42
10,205
At
31 December
Developed
223
57
962
43
302
224
3,190
1,126
30
6,156
Undeveloped
243
100
802
209
264
36
2,414
482
5
4,555
466
157
1,764
253
566
260
5,604
1,608
34
10,711
a Crude
oil includes condensate and bitumen. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 16 million barrels upon which a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust.
d Includes 4 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
e
Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
f Includes 344 million barrels of crude oil in respect of the 6.28% non-controlling interest in Rosneft, including 24 mmbbl held through bp’s interests in Russia other than Rosneft.
g Total proved crude oil reserves held as part of our equity interest in Rosneft is 5,539 million barrels, comprising less than 1 million barrels in Vietnam and Canada, 58 million barrels in Venezuela and 5,481 million barrels in Russia.
248
bp
Annual Report and Form 20-F 2020
Financial statements
Movements in estimated net proved reserves – continued
Total
subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
11
4
177
—
2
31
82
—
5
313
Undeveloped
3
4
69
—
28
—
49
—
1
154
14
8
246
—
30
31
131
—
6
467
At
31 December
Developed
8
4
266
—
2
22
103
—
5
409
Undeveloped
6
3
246
—
25
4
51
—
—
335
14
7
511
—
27
26
154
—
5
744
a Proved
reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities.
d Includes 8 million barrels of NGL in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
e Volumes
of equity-accounted entities include volumes of equity-accounted investments of those entities.
f Includes 12 million barrels of NGLs in respect of the 7.82% non-controlling interest in Rosneft.
g Total proved NGL reserves held as part of our equity interest in Rosneft is 154 million barrels, comprising less than 1 million barrels in Venezuela, Vietnam and Canada, and 154 million barrels in Russia.
bp
Annual Report and Form 20-F 2020
249
Movements in estimated net proved reserves – continued
Total
subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
256
60
1,108
54
297
313
3,206
1,047
36
6,377
Undeveloped
167
93
561
195
297
28
2,300
642
12
4,295
424
153
1,669
249
594
341
5,505
1,688
48
10,672
At
31 December
Developed
231
60
1,228
44
303
245
3,293
1,126
35
6,565
Undeveloped
249
104
1,048
209
289
40
2,465
482
5
4,890
480
164
2,276
253
593
285
5,758
1,608
39
11,456
a Proved
reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 16 million barrels of oil equivalent upon which a net profits royalty will be payable, over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust.
d Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries
and 3 thousand barrels per day for equity-accounted entities.
e Also includes 12 million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
g Includes 356 million barrels in respect of the non-controlling interest in Rosneft, including 24 mmboe held through bp’s interests in Russia other than Rosneft.
h Total proved liquid reserves held as part of our equity interest in Rosneft is 5,693 million barrels, comprising less than 1 million barrels in Canada, 58 million barrels in Venezuela, less than 1 million barrels in Vietnam and 5,635 million barrels
in Russia.
250
bp Annual Report and Form 20-F 2020
Financial statements
Movements
in estimated net proved reserves – continued
Total
subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
523
112
5,238
—
4,136
1,635
6,077
2,771
2,730
23,221
Undeveloped
320
69
3,086
—
3,781
1,656
7,173
4,249
1,505
21,838
843
180
8,323
—
7,917
3,291
13,250
7,020
4,235
45,060
At
31 December
Developed
439
107
6,270
—
3,375
1,704
7,798
3,610
2,630
25,934
Undeveloped
343
55
5,056
4
3,519
1,210
8,719
3,221
1,179
23,305
782
161
11,326
4
6,894
2,914
16,517
6,832
3,809
49,239
a Proved
reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Includes 181 billion cubic feet of natural gas consumed in operations, 139 billion cubic feet in subsidiaries, 42 billion cubic feet in equity-accounted entities.
d Includes 1,573 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
e Volumes
of equity-accounted entities include volumes of equity-accounted investments of those entities.
f Includes 1,211 billion cubic feet of natural gas in respect of the 8.60% non-controlling interest in Rosneft including 480 billion cubic feet held through bp’s interests in Russia other than Rosneft.
g Total proved gas reserves held as part of our equity interest in Rosneft is 14,325 billion cubic feet, comprising 0 billion cubic feet in Canada, 26 billion cubic feet in Venezuela, 15 billion cubic feet in Vietnam, 200 billion cubic feet in Egypt and 14,084 billion cubic feet in Russia.
bp
Annual Report and Form 20-F 2020
251
Movements in estimated net proved reserves – continued
Total
subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
347
80
2,011
54
1,010
595
4,254
1,524
507
10,381
Undeveloped
222
105
1,093
195
949
314
3,536
1,374
272
8,060
569
184
3,104
249
1,959
908
7,790
2,899
779
18,441
At
31 December
Developed
307
79
2,309
44
885
539
4,638
1,749
488
11,037
Undeveloped
308
113
1,919
210
896
249
3,968
1,037
208
8,908
615
192
4,228
253
1,781
788
8,605
2,786
696
19,945
a Proved
reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c 5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent.
d Proved reserves in the Prudhoe Bay field in Alaska include an estimated 16 million barrels of oil equivalent upon which a net profits royalty will be payable, over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust.
e Excludes NGLs from processing plants in which
an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities.
f Includes 31 million barrels of oil equivalent of natural gas consumed in operations, 24 million barrels of oil equivalent in subsidiaries, 7 million barrels of oil equivalent in equity-accounted entities.
g Includes 283 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
h Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
i Includes
565 million barrels of oil equivalent in respect of the non-controlling interest in Rosneft, including 107 mmboe held through bp’s interests in Russia other than Rosneft.
j Total proved reserves held as part of our equity interest in Rosneft is 8,163 million barrels of oil equivalent, comprising less than 1 million barrels of oil equivalent in Canada, 62 million barrels of oil equivalent in Venezuela, 3 million barrels of oil equivalent in Vietnam, 35 million barrels of oil equivalent in Egypt and 8,063 million barrels of oil equivalent in Russia.
252
bp
Annual Report and Form 20-F 2020
Financial statements
Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves
The following tables set out the standardized measure of discounted future net cash flows, and changes therein, relating to crude oil and natural gas production from the group’s estimated proved reserves. This information is prepared in compliance
with FASB Oil and Gas Disclosures requirements.
Future net cash flows have been prepared on the basis of certain assumptions which may or may not be realized. These include the timing of future production, the estimation of crude oil and natural gas reserves and the application of average crude oil and natural gas prices and exchange rates from the previous 12 months. Furthermore, both proved reserves estimates and production forecasts are subject to revision as further technical information becomes available and economic conditions change. bp cautions against relying on the information presented because of the highly arbitrary nature of the assumptions on which it is based and its lack of comparability with the historical cost information presented in the financial statements.
Sales
and transfers of oil and gas produced, net of production costs
(21,200)
(6,000)
(27,200)
Development costs for the current year as estimated in previous year
8,700
4,100
12,800
Extensions, discoveries and improved recovery, less related costs
1,100
1,400
2,500
Net
changes in prices and production cost
(51,600)
(19,200)
(70,800)
Revisions of previous reserves estimates
6,900
400
7,300
Net change in taxation
22,900
4,600
27,500
Future
development costs
100
(2,700)
(2,600)
Net change in purchase and sales of reserves-in-place
(6,200)
—
(6,200)
Addition of 10% annual discount
6,300
3,400
9,700
Total
change in the standardized measure during the yeark
(33,000)
(14,000)
(47,000)
a The marker prices used were Brent $41.31/bbl, Henry Hub $1.94/mmBtu.
b Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future decommissioning costs are included.
c Taxation is computed with reference to appropriate year-end statutory corporate income
tax rates.
d Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities.
e In certain situations, revenues and costs are included in the standardized measure of discounted future net cash flows valuation and excluded from the determination of proved reserves and vice versa. This can result in the standardized measure of discounted future net cash flows being negative.
f Non-controlling interests in BP Trinidad and Tobago LLC amounted to $200 million.
g The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted
future net cash flows of equity-accounted investments of those entities.
h Non-controlling interests in Rosneft amounted to $1,600 million in Russia.
i No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs.
j Includes future net cash flows for assets held for sale at 31 December 2020.
k Total change in the standardized measure during the year includes the effect of exchange rate movements. Exchange rate effects arising from the translation of our share of Rosneft changes to US dollars are included within ‘Net changes in prices and production cost’.
bp
Annual Report and Form 20-F 2020
253
Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves – continued
Sales and transfers of oil and gas produced, net of production costs
(27,400)
(8,400)
(35,800)
Development costs for the current year as estimated in previous year
9,200
4,100
13,300
Extensions, discoveries and improved recovery, less related costs
3,800
2,600
6,400
Net
changes in prices and production cost
(28,100)
(8,200)
(36,300)
Revisions of previous reserves estimates
300
1,100
1,400
Net change in taxation
16,600
2,400
19,000
Future
development costs
(1,500)
(4,300)
(5,800)
Net change in purchase and sales of reserves-in-place
(1,400)
—
(1,400)
Addition of 10% annual discount
8,300
4,100
12,400
Total
change in the standardized measure during the yeark
(20,200)
(6,600)
(26,800)
a The marker prices used were Brent $62.74/bbl, Henry Hub $2.58/mmBtu.
b Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future decommissioning costs are included.
c Taxation is computed with reference to appropriate year-end statutory corporate income tax
rates.
d Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities.
e In certain situations, revenues and costs are included in the standardized measure of discounted future net cash flows valuation and excluded from the determination of proved reserves and vice versa. This can result in the standardized measure of discounted future net cash flows being negative.
f Non-controlling interests in BP Trinidad and Tobago LLC amounted to $600 million.
g The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted
future net cash flows of equity-accounted investments of those entities.
h Non-controlling interests in Rosneft amounted to $2,100 million in Russia.
i No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs.
i Includes future net cash flows for assets held for sale at 31 December 2019.
k Total change in the standardized measure during the year includes the effect of exchange rate movements. Exchange rate effects arising from the translation of our share of Rosneft changes to US dollars are included within ‘Net changes in prices and production cost’.
254
bp
Annual Report and Form 20-F 2020
Financial statements
Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves – continued
Sales
and transfers of oil and gas produced, net of production costs
(18,800)
(8,000)
(26,800)
Development costs for the current year as estimated in previous year
8,500
4,300
12,800
Extensions, discoveries and improved recovery, less related costs
5,800
3,300
9,100
Net
changes in prices and production cost
41,000
13,100
54,100
Revisions of previous reserves estimates
(2,100)
2,000
(100)
Net change in taxation
(17,000)
(4,600)
(21,600)
Future
development costs
1,000
(3,500)
(2,500)
Net change in purchase and sales of reserves-in-place
7,600
400
8,000
Addition of 10% annual discount
5,200
3,100
8,300
Total
change in the standardized measure during the yearj
31,200
10,100
41,300
a The marker prices used were Brent $71.43/bbl, Henry Hub $3.10/mmBtu.
b Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future decommissioning costs are included. 2018 comparative for Russia equity-accounted entity future production cost has been restated from $232,100 million to maintain consistency with 2019 presentation.
c Taxation
is computed with reference to appropriate year-end statutory corporate income tax rates. 2018 comparative for Russia equity-accounted entity future taxation has been restated from $24,000 million to maintain consistency with 2019 presentation.
d Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities.
e In certain situations, revenues and costs are included in the standardized measure of discounted future net cash flows valuation and excluded from the determination of proved reserves and vice versa. This can result in the standardized measure of discounted future net cash flows being negative.
f Non-controlling interests in BP Trinidad and Tobago LLC
amounted to $1,100 million.
g The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments of those entities.
h Non-controlling interests in Rosneft amounted to $2,500 million in Russia.
i No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs.
j Total change in the standardized measure during the year includes the effect of exchange rate movements. Exchange rate effects arising from the translation of our share of Rosneft changes to US dollars are included within ‘Net
changes in prices and production cost’.
bp Annual Report and Form 20-F 2020
255
Operational and statistical
information
The following tables present operational and statistical information related to production, drilling, productive wells and acreage. Figures include amounts attributable to assets held for sale.
Crude oil and natural gas production
The following table shows crude oil, natural gas liquids and natural gas production for the years ended 31 December 2020, 2019 and 2018.
a Production
excludes royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Amounts reported for Russia include bp’s share of Rosneft worldwide activities, including insignificant amounts outside Russia.
d All of the oil and liquid production from Canada is bitumen.
e Crude oil includes condensate.
f Natural gas production excludes gas consumed in operations.
256
bp
Annual Report and Form 20-F 2020
Financial statements
Operational and statistical information – continued
Productive oil and gas wells and acreage
The following tables show the number of gross and net productive oil and natural gas wells and total gross and net developed and undeveloped oil and natural gas acreage in which the group and its equity-accounted entities had interests as at 31 December 2020. A ‘gross’ well or acre is one in which a whole or fractional working interest is owned,
while the number of ‘net’ wells or acres is the sum of the whole or fractional working interests in gross wells or acres. Productive wells are producing wells and wells capable of production. Developed acreage is the acreage within the boundary of a field, on which development wells have been drilled, which could produce the reserves; while undeveloped acres are those on which wells have not been drilled or completed to a point that would permit the production of commercial quantities, whether or not such acres contain proved reserves.
Europe
North
America
South America
Africa
Asia
Australasia
Totalb
UK
Rest of Europe
US
Rest of North America
Russiaa
Rest of Asia
Number
of productive wells at 31 December 2020
Oil wellsc
– gross
125
90
1,326
175
5,551
291
68,286
2,020
12
77,876
–
net
73
27
741
47
2,557
62
13,594
475
2
17,578
Gas
wellsd
– gross
39
2
6,405
238
1,118
241
455
138
78
8,714
–
net
8
1
3,898
118
403
102
93
70
16
4,709
Oil
and natural gas acreage at 31 December 2020
thousands of acres
Developed
– gross
86
64
3,645
144
1,364
850
8,210
1,281
181
15,824
–
net
50
19
2,200
63
365
303
1,459
285
44
4,788
Undevelopede
– gross
1,892
140
4,590
14,948
23,683
34,246
442,967
9,662
7,571
539,699
–
net
1,010
42
3,518
7,887
8,358
19,817
85,477
2,520
3,299
131,928
a Based
on information received from Rosneft as at 31 December 2020.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Includes approximately 6,978 gross (1,343 net) multiple completion wells (more than one formation producing into the same well bore).
d Includes approximately 430 gross (203 net) multiple completion wells. If one of the multiple completions in a well is an oil completion, the well is classified as an oil well.
e Undeveloped acreage includes leases and concessions.
Net oil and gas wells completed or abandoned
The following table shows the number
of net productive and dry exploratory and development oil and natural gas wells completed or abandoned in the years indicated by the group and its equity-accounted entities. Productive wells include wells in which hydrocarbons were encountered and the drilling or completion of which, in the case of exploratory wells, has been suspended pending further drilling or evaluation. A dry well is one found to be incapable of producing hydrocarbons in sufficient quantities to justify completion.
Europe
North
America
South America
Africa
Asia
Australasia
Totala
UK
Rest of Europe
US
Rest of North America
Russia
Rest of Asia
2020
Exploratory
Productive
—
—
1.1
0.8
—
0.6
14.3
0.4
—
17.2
Dry
—
—
1.8
—
—
—
—
0.2
—
2.0
Development
Productive
5.3
3.1
114.6
0.4
61.7
4.4
199.1
40.3
2.0
430.9
Dry
—
—
3.0
—
1.0
—
—
0.6
—
4.6
2019
Exploratory
Productive
—
0.2
0.8
0.8
3.5
2.3
11.6
5.2
—
24.4
Dry
1.0
0.3
1.6
0.5
1.1
0.3
0.5
0.4
0.2
5.9
Development
Productive
1.7
2.4
193.0
0.2
110.7
6.0
230.8
49.6
0.4
594.8
Dry
—
0.3
10.0
—
0.6
—
—
1.0
—
11.9
2018
Exploratory
Productive
0.3
—
1.7
—
2.0
—
15.0
5.0
—
24.0
Dry
—
—
—
0.5
2.0
2.4
—
—
—
4.9
Development
Productive
1.4
0.6
142.7
5.0
103.9
14.4
137.3
53.5
1.3
460.1
Dry
—
—
6.8
—
3.6
—
—
2.6
—
13.0
a Because
of rounding, some totals may not exactly agree with the sum of their component parts.
bp Annual Report and Form 20-F 2020
257
Operational and statistical information – continued
Drilling and production activities in progress
The
following table shows the number of exploratory and development oil and natural gas wells in the process of being drilled by the group and its equity-accounted entities as of 31 December 2020. Suspended development wells and long-term suspended exploratory wells are also included in the table.
Europe
North
America
South America
Africa
Asia
Australasia
Totala
UK
Rest of Europe
US
Rest of North America
Russia
Rest of Asia
At
31 December 2020
Exploratory
Gross
—
—
5.0
1.0
2.0
7.0
—
4.0
1.0
20.0
Net
—
—
3.1
0.4
0.1
3.2
—
0.8
0.4
8.0
Development
Gross
2.0
0.7
166.0
6.0
13.0
19.0
—
198.0
2.0
406.7
Net
0.7
0.2
104.8
3.0
4.7
4.8
—
25.0
0.8
144.0
a Because
of rounding, some totals may not exactly agree with the sum of their component parts.
258
bp Annual Report and Form 20-F 2020
Financial
statements
Pages 259-300 have been removed as they do not form part of bp's Annual Report on Form 20-F as filed with the SEC.
This information has been extracted or derived from the audited consolidated financial statements of the bp group. Note 1 to the financial statements includes details on the basis of preparation of these financial statements. The selected information should be read in conjunction with the audited financial statements and related notes. The audited consolidated financial statements and related notes as of 31 December 2020 and 2019 and for the three years ended 31 December 2020 are presented on page
150.
$ million except per share amounts
2020
2019
2018
2017
2016
Income
statement data
Sales and other operating revenues
180,366
278,397
298,756
240,208
183,008
Profit (loss) before interest and taxation
(21,740)
11,706
19,378
9,474
(430)
Finance
costs and net finance expense relating to pensions and other post-retirement benefits
(3,148)
(3,552)
(2,655)
(2,294)
(1,865)
Taxation
4,159
(3,964)
(7,145)
(3,712)
2,467
Non-controlling
interests
424
(164)
(195)
(79)
(57)
Profit (loss) for the yeara
(20,305)
4,026
9,383
3,389
115
Inventory
holding (gains) losses«, before tax
2,868
(667)
801
(853)
(1,597)
Taxation charge (credit) on inventory holding gains and losses
(667)
156
(198)
225
483
RC
profit (loss)« for the year
(18,104)
3,515
9,986
2,761
(999)
Net (favourable) adverse impact of non-operating items«b and fair value accounting effects«b, before tax
16,649
8,263
3,380
3,730
6,746
Taxation
charge (credit) on non-operating items and fair value accounting effects, and certain foreign exchange impacts on the group’s tax charge for the period
(4,235)
(1,788)
(643)
(325)
(3,162)
Underlying RC profit« for the year
(5,690)
9,990
12,723
6,166
2,585
Earnings
per sharec – cents
Profit (loss) for the yeara per ordinary share
Basic
(100.42)
19.84
46.98
17.20
0.61
Diluted
(100.42)
19.73
46.67
17.10
0.60
RC
profit (loss) for the year per ordinary share«
(89.53)
17.32
50.00
14.02
(5.33)
Underlying RC profit for the year per ordinary share«
(28.14)
49.24
63.70
31.31
13.79
Dividends
paid per share – cents
31.50
41.00
40.50
40.00
40.00
– pence
24.458
31.977
30.568
30.979
29.418
Capital
expenditure«d
Organic capital expenditure«
12,034
15,238
15,140
16,501
16,675
Inorganic capital expenditure«
2,021
4,183
9,948
1,339
777
14,055
19,421
25,088
17,840
17,452
Balance
sheet data (at 31 December)
Total assets
267,654
295,194
282,176
276,515
263,316
Net assets
85,568
100,708
101,548
100,404
96,843
Share
capital
5,383
5,404
5,402
5,343
5,284
bp shareholders’ equity
71,250
98,412
99,444
98,491
95,286
Finance
debt due after more than one year
63,305
57,237
55,803
54,873
51,073
Gearing«
31.3%
31.1%
30.0%
27.0%
26.5%
Ordinary
share datae
Share million
Basic weighted average number of shares
20,222
20,285
19,970
19,693
18,745
Diluted weighted average number of shares
20,222
20,400
20,102
19,816
18,855
a Profit
attributable to bp shareholders.
b See pages 304 and 305 for further analysis of these items.
c A reconciliation to GAAP information is provided on page 348.
d From 2017 onwards bp reports organic, inorganic and total capital expenditure on a cash basis which were previously reported on an accruals basis. This aligns with bp's financial framework and is consistent with other financial metrics used when comparing sources and uses of cash.
e The number of ordinary shares shown has been used to calculate the per share amounts.
302
bp
Annual Report and Form 20-F 2020
«See Glossary
Additional disclosures
Additional information
Capital expenditure
$ million
2020
2019
2018
Capital
expenditure
Organic capital expenditure
12,034
15,238
15,140
Inorganic capital expenditureab
2,021
4,183
9,948
14,055
19,421
25,088
$ million
2020
2019
2018
Organic
capital expenditure by segment
Upstream
US
3,341
4,019
3,482
Non-US
6,009
7,885
8,545
9,350
11,904
12,027
Downstream
US
632
913
877
Non-US
1,698
2,084
1,904
2,330
2,997
2,781
Other
businesses and corporate
US
80
47
54
Non-US
274
290
278
354
337
332
12,034
15,238
15,140
Organic
capital expenditure by geographical area
US
4,053
4,979
4,413
Non-US
7,981
10,259
10,727
12,034
15,238
15,140
a
On 31 October 2018, bp acquired from BHP Billiton Petroleum (North America) Inc. 100% of the issued share capital of Petrohawk Energy Corporation, a wholly owned subsidiary of BHP that holds a portfolio of unconventional onshore US oil and gas assets. The entire consideration payable of $10,268 million, after customary closing adjustments, was paid in instalments between July 2018 and April 2019. The amounts presented as inorganic capital expenditure include $3,480 million for 2019 and $6,788 million for 2018 relating to this transaction. 2018 includes $1,739 million relating to the purchase of an additional 16.5% interest in the Clair field west of Shetland in the North Sea, as part of the agreements with Conoco-Phillips in which Conoco-Philips simultaneously purchased bp's entire 39.2% interest in the Greater Kuparuk Area on the North Slope of Alaska. 2020, 2019 and 2018 also include amounts relating to the 25-year extension to our ACG production-sharing
agreement« in Azerbaijan.
b 2020 includes a $500 million deposit in respect of the strategic partnership with Equinor and $1 billion relating to an investment in a 49% interest in the group's Indian fuels and mobility venture with Reliance industries.
«See Glossary
bp
Annual Report and Form 20-F 2020
303
Non-operating items
Non-operating items are charges and credits included in the financial statements that bp discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management considers not to be part of underlying business operations and are disclosed in order to enable investors to understand better and evaluate the group’s reported financial performance. An analysis of non-operating items is shown in the table below.
$ million
2020
2019
2018
Upstream
Gain
on sale of businesses and fixed assetsa
360
143
437
Impairment and losses on sale of businesses and fixed assetsa b
(13,214)
(7,036)
(527)
Environmental and other provisions
(2)
(32)
(35)
Restructuring,
integration and rationalization costsc
(401)
(89)
(131)
Fair value gain (loss) on embedded derivatives
—
—
17
Otherd e
(2,511)
67
56
(15,768)
(6,947)
(183)
Downstream
Gain
on sale of businesses and fixed assetsa f
2,320
50
15
Impairment and losses on sale of businesses and fixed assetsa
(1,136)
(122)
(69)
Environmental and other provisions
(33)
(78)
(83)
Restructuring,
integration and rationalization costsc
(633)
85
(405)
Fair value gain (loss) on embedded derivatives
—
—
—
Other
(39)
(12)
(174)
479
(77)
(716)
Rosneft
Other
(205)
(103)
(95)
(205)
(103)
(95)
Other
businesses and corporate
Gain on sale of businesses and fixed assetsa
194
—
4
Impairment and losses on sale of businesses and fixed assetsa g
(19)
(917)
(264)
Environmental
and other provisionsh
(177)
(231)
(640)
Restructuring, integration and rationalization costsc
(262)
6
(190)
Fair value gain (loss) on embedded derivatives
—
—
—
Gulf
of Mexico oil spill response
(255)
(319)
(714)
Otheri
201
(30)
(159)
(318)
(1,491)
(1,963)
Total
before interest and taxation
(15,812)
(8,618)
(2,957)
Finance costsj
(625)
(511)
(479)
Total before taxation
(16,437)
(9,129)
(3,436)
Taxation
credit (charge) on non-operating items
4,345
1,943
510
Taxation - impact of US tax reformk
—
—
121
Taxation - impact of foreign exchangel
(99)
—
—
Total
after taxation
(12,191)
(7,186)
(2,805)
a See Financial statements – Note 4 for further information.
b 2020 impairment charges for Upstream include $156 million in relation to the likely disposal of an exploration asset. 2019 includes impairments charges principally resulting from the announcements to dispose of certain assets in the US and Egypt. 2018 includes an impairment reversal for assets in the North Sea and Angola.
c Restructuring charges are classified as non-operating items where they relate
to an announced major group restructuring. A major group restructuring is a restructuring programme affecting more than one of the group’s operating segments that is expected to result in charges of more than $1 billion over a defined period. 2020 includes recognized provisions for restructuring costs for plans that were formalized during the year. 2018 includes amounts related to the programme originally announced in 2014 that was completed in 2018.
d2020 includes exploration write-offs of $1,974 million relating to fair value ascribed to certain licences as part of the accounting at the time of acquisition of upstream assets in Brazil, India and the Gulf of Mexico and the impairment of certain intangible assets in Mauritania and Senegal. 2018 includes exploration write-offs of $124 million in relation to the value ascribed to certain licences in the deepwater Gulf of Mexico
as part of the accounting for the acquisition of upstream assets from Devon Energy in 2011.
e 2020 includes $545 million net impairments reported by equity-accounted entities.
f 2020 includes a gain of $2.3 billion on the sale of our petrochemicals business.
g 2019 includes $877 million relating to the reclassification of accumulated foreign exchange losses from reserves to the income statement upon the contribution of our Brazilian biofuels business to BP Bunge Bioenergia.
h All periods primarily reflect charges due to the annual update of environmental provisions, including asbestos-related provisions for past operations, together with updates of non-Gulf of Mexico oil spill related
legal provisions.
i From 2020, BP is presenting temporary valuation differences associated with the group’s interest rate and foreign currency exchange risk management of finance debt as non-operating items. These amounts represent: (i) the impact of ineffectiveness and the amortisation of cross currency basis resulting from the application of fair value hedge accounting; and (ii) the net impact of foreign currency exchange movements on finance debt and associated derivatives where hedge accounting is not applied. Relevant amounts in the comparative periods presented were not material.
j All periods presented include the unwinding of discounting effects relating to Gulf of Mexico oil spill payables. 2020 also includes the income statement impact associated with the buyback of finance debt. See Note 26 for further information.
k In
2017 the US tax reform reduced the US federal corporate income tax rate from 35% to 21%, effective from 1 January 2018. 2018 reflects a further impact following a clarification of the tax reform. The impact of the US tax reform has been treated as a non-operating item because it is not considered to be part of underlying business operations, has a material impact upon the reported result and is substantially impacted by Gulf of Mexico oil spill charges, which are also treated as non-operating items. Separate disclosure is considered meaningful and relevant to investors.
l From 2020, bp is presenting certain foreign exchange effects on tax as non-operating items. These amounts represent the impact of: (i) foreign exchange on deferred tax balances arising from the conversion of local currency tax base amounts into functional currency, and (ii) taxable gains and losses from the retranslation of US
dollar-denominated intra-group loans to local currency. Relevant amounts in the comparative periods presented were not material.
304
bp Annual Report and Form 20-F 2020
«See Glossary
Additional
disclosures
Non-GAAP information on fair value accounting effects
The impacts of fair value accounting effects, relative to management’s internal measure of performance, and a reconciliation to GAAP information is set out below. Further information on fair value accounting effects is provided on page 344.
$ million
2020
2019
2018
Upstream
Unrecognized
(gains) losses brought forward from previous perioda
253
(455)
(419)
Favourable (adverse) impact relative to management’s measure of performance
(738)
706
(39)
Exchange translation gains (losses) on fair value accounting effects
—
2
3
Unrecognized
(gains) losses carried forward
(485)
253
(455)
Downstream
Unrecognized (gains) losses brought forward from previous perioda
104
(56)
(151)
Favourable
(adverse) impact relative to management’s measure of performance
(149)
160
95
Unrecognized (gains) losses carried forward
(45)
104
(56)
Other businesses and corporate
Favourable
(adverse) impact relative to management’s measure of performanceb
675
—
—
Unrecognized (gains) losses carried forward
675
—
—
Favourable (adverse) impact relative to management’s measure of performance – by region
Upstream
US
198
(179)
(35)
Non-US
(936)
885
(4)
(738)
706
(39)
Downstream
US
27
148
(155)
Non-US
(176)
12
250
(149)
160
95
Other
businesses and corporate
US
—
—
—
Non-US
675
—
—
675
—
—
(212)
866
56
Taxation
credit (charge)
(11)
(155)
12
(223)
711
68
a 2018 brought forward fair value accounting effect balances include a $55-million adjustment between Upstream and Downstream as part of the transfer of the NGL business between segments.
b From 2020 fair value accounting effects include changes
in the fair value of derivatives entered into by the group to manage currency exposure and interest rate risks relating to hybrid bonds to their respective first call periods. For further information see page 344.
Net debt including leases
Net debt including leases« is shown in the table below.
$ million
At
31 December
2020
2019
Net debt«
38,941
45,442
Lease liabilities
9,262
9,722
Net partner (receivable) payable for leases entered into on behalf of joint operations«
(7)
(158)
Net
debt including leases
48,196
55,006
Total equity
85,568
100,708
Gearing including leases«
36.0%
35.3%
«See Glossary
bp Annual Report and Form 20-F 2020
305
Liquidity and capital resources
Financial framework
bp has a resilient financial framework that, taken together with our strategy, creates a compelling investor proposition offering committed distributions, profitable growth and sustainable value. The framework comprises a coherent approach to capital allocation, a resilient
balance sheet, a disciplined approach to investment allocation and a relentless focus on executing bp’s business plan.
bp’s approach to capital allocation leads to a clear set of priorities – funding our resilient dividend as the first priority, deleveraging the balance sheet, investment in low carbon« and convenience and mobility to advance our energy transition strategy, investment in resilient hydrocarbons to generate sustainable cash flow, and then returning surplus cash« as share buybacks. In a period of low prices, the group has the flexibility to reduce cash costs and to reduce or defer capital investment, as appropriate.
Our shareholder distribution policy reflects these priorities for the uses of cash alongside an ongoing consideration of factors, including changes in the environment,
the underlying performance of the business, the outlook for the group financial framework, and other market factors which may vary quarter to quarter.
Net debt« at 31 December 2020 was $38.9 billion and is expected to reduce in line with the receipt of divestment proceeds and the growth in operating cash flow« . bp is targeting $25 billion of proceeds by 2025 (from mid 2020), and at the end of 2020 bp had completed or agreed transactions for over half of this target.
We expect operating cash flow to cover capital expenditure« and the dividend, with capital expenditure initially in a range of $13-15 billion, before increasing to $14-16 billion once net debt reaches $35 billion. Capital expenditure is expected to be at the lower end of the initial
range in 2021. Looking further out across 2021-25, bp's cash balancing point is expected to average around $40 per barrel (assuming an average refining marker margin of around $11 and Henry Hub gas price at $3) in 2020 real terms. Gulf of Mexico oil spill payments on a post-tax basis were just over $1.6 billion in 2020 and are expected to be around $1 billion in 2021.
In 2020, the return on average capital employed« was (3.8)%a at an average of $42 per barrel. The return on average capital employed is targeted to grow to 12-14% by 2025 at $50 to 60 per barrel in 2020 real terms, and assuming bp planning assumptions, as we continue to execute our strategy. This is supported by an expected 7-9% growth in earnings before interest, tax, depreciation
and amortization (compound annual growth rate) across the same period and subject to the same price and planning assumptions.
a Nearest equivalent GAAP measures: Numerator – Loss attributable to bp shareholders $(20.3); Denominator – Average capital employed $163.3 billion.
Dividends and other distributions to shareholders
The dividend is determined in US dollars, the economic currency of bp, and the dividend level is reviewed by the board each quarter. The quarterly dividend was reset to 5.25 cents per ordinary share per quarter as part of a wider distribution policy announced in August 2020, and is intended to remain fixed at this level.
The total dividend distributed to bp shareholders in 2020 was $6.4 billion (2019 $8.3 billion). This dividend was all paid in cash
as shareholders no longer have the option to receive a scrip dividend in place of receiving cash.
Included in the distribution policy is a commitment that, once net debt reaches $35 billion and subject to maintaining a strong investment grade credit rating, at least 60% of surplus cash will be distributed to shareholders through share buybacks.
The share buyback programme to offset the dilutive impact of the legacy scrip dividend concluded in January 2020 and purchased 120 million ordinary shares in 2020 at a cost of $776 million (2019 $1.5 billion), including fees and stamp duty.
Financing the group’s activities
The group’s principal commodities, oil and gas, are priced internationally in US dollars. Group policy has generally been to minimize economic
exposure to currency movements by financing operations with US dollar debt. Where debt and hybrid bonds are issued in other currencies, they are generally swapped back to US dollars using derivative contracts, or else hedged by maintaining offsetting cash positions in the same currency. Cash balances of the group are mainly held in US dollars or swapped to US dollars and holdings are well diversified to reduce concentration risk. The group is not, therefore, exposed to significant currency risk regarding its cash or borrowings. Also see Risk factors on page 67 for further information on risks associated with prices and markets and Financial statements – Note 29.
The group’s finance debt at 31 December 2020 amounted to $72.7 billion (2019 $67.7 billion). Of the total finance debt, $9.4 billion is classified as short term at the end of
2020 (2019 $10.5 billion). See Financial statements – Note 26 for more information on the short-term balance. Net debt« was $38.9 billion at the end of 2020, a decrease of $6.5 billion from the 2019 year-end position of $45.4 billion.
On 17 June 2020, a group subsidiary« issued perpetual subordinated hybrid bonds in EUR, GBP and USD for a US dollar equivalent amount of $11.9 billion. As the group has the unconditional right to avoid transferring cash or another financial asset in relation to these hybrid bonds, they are classified as equity instruments and reported within non-controlling interests.
The ratio of finance debt to finance debt plus total equity at 31 December 2020 was 45.9% (2019 40.2%). Gearing was i31.3%
at the end of 2020 (2019 31.1%). See Financial statements – Note 27 for finance debt, which is the nearest equivalent measure on an IFRS basis, and for further information on net debt.
Cash and cash equivalents of $31.1 billion at 31 December 2020 (2019 $22.5 billion) are included in net debt. We manage our cash position so that the group has adequate cover to respond to potential short-term market liquidity, short term price environment volatility and expect to maintain a robust cash position.
The group also has an undrawn committed $8 billion credit facility and undrawn committed bank facilities of $4 billion (see Financial statements – Note 29 for more information).
We believe that the group has sufficient working capital for foreseeable requirements, taking into account the amounts of undrawn borrowing facilities and levels of cash
and cash equivalents, and its ongoing ability to generate cash.
bp utilizes various arrangements in order to manage its working capital including discounting of receivables and, in the supply and trading business, the active management of supplier payment terms, inventory and collateral.
Standard & Poor’s Ratings’ long-term credit rating for BP p.l.c. is A- (negative outlook), the Moody’s Investors Service rating is A1 (negative outlook) and the Fitch Ratings’ long-term credit rating is A (stable).
The group’s sources of funding, its access to capital markets and maintaining a strong cash position are described in Financial statements – Note 25 and Note 29. Further information on the management of liquidity risk and credit risk, and the maturity profile and fixed/floating rate characteristics of the group’s debt are also provided in
Financial statements– Note 26 and Note 29.
The information above contains forward-looking statements, which by their nature involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future and are outside the control of bp. You are urged to read the Cautionary statement on page 329 and Risk factors on page 67, which describe the risks and uncertainties that may cause actual results and developments to differ materially from those expressed or implied by these forward-looking statements.
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bp
Annual Report and Form 20-F 2020
«See Glossary
Additional disclosures
Off-balance sheet arrangements
At 31 December 2020, the group’s share of third-party finance debt of equity-accounted entities was $19.9 billion (2019 $17.3 billion). These amounts are not reflected in the group’s debt on the balance sheet. The group has issued third-party guarantees under which amounts outstanding, incremental to amounts recognized on the balance sheet, at
31 December 2020 were $1,405 million (2019 $692 million) in respect of liabilities of joint ventures« and associates« and $661 million (2019 $523 million) in respect of liabilities of other third parties. Of these amounts, $1,393 million (2019 $681 million) of the joint ventures and associates guarantees relate to borrowings and for other third-party guarantees, $568 million (2019 $494 million) relate to guarantees of borrowings.
Contractual obligations
The following table summarizes the group’s capital expenditure commitments for property, plant and equipment at 31 December 2020 and the proportion of that expenditure for which contracts have been placed.
$ million
Payments due by period
Capital
expenditure
Total
2021
2022
2023
2024
2025
2026 and thereafter
Committed
18,025
9,016
5,467
1,747
747
505
543
of
which is contracted
8,009
4,878
2,805
166
65
27
68
Capital expenditure is considered to be committed when the project has received the appropriate level of internal management approval. For joint operations«, the net bp share is included in the amounts above.
In addition, at 31 December
2020, the group had committed to capital expenditure relating to investments in equity-accounted entities amounting to $3,774 million. Contracts were in place for $1,270 million of this total.
The following table summarizes the group’s principal contractual obligations at 31 December 2020, distinguishing between those for which a liability is recognized on the balance sheet and those for which no liability is recognized. Further information on borrowings is given in Financial statements – Note 26 and more information on leases is given in Financial statements – Note 28.
$ million
Payments
due by period
Expected payments by period under contractual obligations
Total
2021
2022
2023
2024
2025
2026 and thereafter
Balance sheet obligations
Borrowingsa
81,076
13,981
7,541
8,146
9,001
7,445
34,962
Lease
liabilitiesb
10,884
2,262
1,672
1,340
1,025
878
3,707
Decommissioning liabilitiesc
22,466
470
244
279
233
221
21,019
Environmental
liabilitiesc
1,880
272
290
242
196
157
723
Gulf of Mexico oil spill liabilitiesd
14,569
1,409
1,278
1,222
1,141
1,136
8,383
Pensions
and other post-retirement benefitse
17,448
1,039
978
946
922
917
12,646
148,323
19,433
12,003
12,175
12,518
10,754
81,440
Off-balance
sheet obligations
Unconditional purchase obligationsf
Crude oil and oil products
44,322
35,702
4,495
1,988
993
477
667
Natural
gas and LNG
35,337
11,255
4,779
3,155
2,442
1,465
12,241
Chemicals and other refinery feedstocks
684
422
70
63
54
53
22
Power
4,240
2,124
730
364
176
193
653
Utilities
762
91
91
53
51
50
426
Transportation
19,270
1,792
1,529
1,459
1,357
1,189
11,944
Use
of facilities and services
19,830
2,810
2,010
1,628
1,358
1,207
10,817
124,445
54,196
13,704
8,710
6,431
4,634
36,770
Total
272,768
73,629
25,707
20,885
18,949
15,388
118,210
a Expected
payments include interest totalling $8,412 million ($1,503 million in 2021, $1,249 million in 2022, $1,115 million in 2023, $954 million in 2024, $793 million in 2025 and $2,798 million thereafter).
b Expected payments include interest totalling $1,622 million ($275 million in 2021, $228 million in 2022, $190 million in 2023, $156 million in 2024, $126 million in 2025 and $647 million thereafter).
c The amounts presented are undiscounted.
d The amounts presented are undiscounted. Gulf of Mexico oil spill liabilities are included in the group balance sheet, on a discounted basis, within other payables. See Financial statements – Note 22 for further information.
e Represents the expected
future contributions to funded pension plans and payments by the group for unfunded pension plans and the expected future payments for other post-retirement benefits.
f Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms (such as fixed or minimum purchase volumes, timing of purchase and pricing provisions). Agreements that do not specify all significant terms, or that are not enforceable, are excluded. The amounts shown include arrangements to secure long-term access to supplies of crude oil, natural gas, feedstocks and pipeline systems. In addition, the amounts shown for 2021 include purchase commitments existing at 31 December 2020 entered into principally to meet the group’s short-term manufacturing and marketing requirements. The price risk associated with these crude oil, natural gas and power contracts
is discussed in Financial statements – Note 29.
Commitments for the delivery of oil and gas
We sell crude oil, natural gas and liquefied natural gas under a variety of contractual obligations. Some of these contracts specify the delivery of fixed and determinable quantities. For the period from 2021 to 2023 worldwide, we are contractually committed to deliver approximately 228 million barrels of oil, 8,500 billion cubic feet of natural gas, and 37 million tonnes of liquefied natural gas. The commitments principally relate to group subsidiaries« based in Canada, Egypt,
Singapore, United Kingdom and United States. We expect to fulfil these delivery commitments with production from our proved developed reserves and supplies from existing contracts, supplemented by market purchases as necessary.
«See Glossary
bp Annual Report and Form 20-F 2020
307
Oil
and gas disclosures for the group
Analysis by region
Our oil and gas operations are set out below by geographical area, with associated significant events for 2020. bp’s percentage working interest in oil and gas assets is shown in brackets. Working interest is the cost-bearing ownership share of an oil or gas lease. Consequently, the percentages disclosed for certain agreements do not necessarily reflect the percentage interests in proved reserves, production or revenue. See page 320 for more information on Rosneft.
In addition to exploration, development and production activities, our Upstream business also includes certain midstream and liquefied natural gas (LNG) supply activities. Midstream activities involve the ownership and management of crude oil and natural gas pipelines, processing facilities and export terminals, LNG processing
facilities and transportation, and our natural gas liquids (NGLs) processing business.
Our LNG activities are located in Abu Dhabi, Angola, Australia, Indonesia and Trinidad. In 2020 we marketed around 5.0 million tonnes of LNG production from these assets to IST which supplements equity production with merchant third party volumes to build a global trading portfolio. The LNG is marketed through contractual rights to access import terminal capacity in the liquid markets of Europe, UK and US, and relationships to market directly to end user customers or trading entities. LNG is supplied to all major LNG demand centres for example Argentina, Brazil, Caribbean, China, Croatia, Mediterranean and North West Europe, India, Israel, Japan, Singapore, South Korea, Taiwan, Thailand, Turkey and the UK.
Europe
bp is active in the North Sea and the
Norwegian Sea. In 2020 bp’s production came from three key areas: the Shetland area comprising the Clair, Foinaven, and Schiehallion fields; the central area comprising the Andrew area, Culzean, ETAP and Shearwater fields; and Norway, through our equity accounted 30% interest in Aker BP.
•On 29 March, bp confirmed completion of the restructuring of contractual arrangements for the Petrojari Foinaven floating production, storage and offloading vessel on the Foinaven field to the west of the Shetlands (bp 72% and operator).
•During the year, impairment charges of $2,796 million were recognized in respect of certain North Sea assets, primarily as a result of changes to the group's long-term price assumptions.
•In March 2020, EnQuest, the Thistle field operator, announced
it no longer expected to re-start production at the Thistle field (bp 82%) . A Cessation of Production application was approved by the regulator in July, with an effective decommissioning date of 31 May 2020.
•During the third quarter, bp was awarded eight operated and three non-operated blocks in the North Sea as part of the UK Oil & Gas Authority 32nd offshore licensing round.
•On 6 October, bp confirmed that the planned divestment to Premier Oil of its interests in the Andrew area and Shearwater assets, both located in the UK North Sea, would not proceed following the announcement of a proposed merger between Chrysaor and Premier Oil. bp had announced this divestment in January 2020. The divestment was to cover the Andrew, Arundel, Cyrus, Farragon and Kinnoull fields plus bp's interest in Shearwater. Marketing of both assets
continues.
•On 26 November, bp announced that production had started at the Vorlich field (bp 66%), just two years after the project was sanctioned. Vorlich is the latest in a programme of fast-paced, high-return subsea tiebacks in the UK North Sea. bp and partner Ithaca Energy invested £230 million to develop the field, which was discovered in 2014 and received regulatory approval for development in 2018.
North America
Our upstream activities in North America are located in four areas: deepwater Gulf of Mexico, the Lower 48 states, Canada and Mexico. Our interests in Alaska were disposed of during the year, further details are provided below.
bp has around 260 lease blocks in the Gulf of Mexico and operates four production hubs.
•On
25 August, bp confirmed it started production at Atlantis Phase 3 in the US Gulf of Mexico (bp 56% and operator).
•Construction and installation at the Thunder Horse South Expansion Phase 2 project is underway and drilling set to commence in the first half of 2021. First oil from the project is expected in the third quarter of 2021.
•bp was awarded 12 leases in the lease sale conducted in March and 10 leases in the sale held in November.
•The Mad Dog 2 project execute timeline was impacted by both COVID-19 and delays to fabrication of the floating production unit. The unit has now set sail from Korea, and wells activity and subsea installation are once again progressing. First oil is now expected in the second quarter of 2022.
•During
the year, exploration write-offs of $2,643 million were recognized in relation to certain Gulf of Mexico assets, primarily due to management's re-assessment of expectations to extract value from certain exploration prospects as a result of a review of the group's long-term strategic plan and changes in the group's long-term price assumptions.
See also Financial Statements – Note 1 for further information on exploration leases.
bpx energy, bp's onshore oil and gas business in the Lower 48 states, has significant operated and non-operated activities across Louisiana, Texas and Wyoming producing natural gas, oil, NGLs and condensate, with primary focus on developing unconventional resources in Texas. It had a 1.5 billion boe proved reserve base at 31 December 2020, predominantly in unconventional reservoirs (tight gas«, shale gas and newly
acquired shale oil). BPX Energy's assets span 2.1 million net developed acres and it had over 7,000 operated gross wells at 31 December 2020, with daily net production around 370mboe/d.
bpx energy operated as a separate business in 2020 while remaining part of the Upstream segment. With its own governance, systems and processes, it is structured to increase competitive performance through swift decision making and innovation, while maintaining bp’s commitment to safe, reliable and compliant operations.
•During the year, impairment charges of $1,444 million were recognized in respect of certain bpx energy assets, primarily as a result of changes to the group's long term price assumptions.
•In December bp announced that it had reached agreement to sell its interest in the Wamsutter asset in
Wyoming to Williams Field Services LLC. The transaction completed in January 2021.
bp’s onshore US crude oil and product pipelines and related transportation assets were included in the Downstream segment in 2020.
In Alaska, BP Exploration (Alaska) Inc. (BPXA) operated nine North Slope oilfields in the Greater Prudhoe Bay area and held interests in three producing fields operated by others, as well as a non-operating interest in the Liberty development project prior to the completion in the second quarter of 2020 of the divestment of its Upstream business to Hilcorp Energy announced in 2019.
BP Pipelines (Alaska) Inc. (BPPA) owned a 49% interest in the Trans-Alaska Pipeline System (TAPS) prior to completion in the fourth quarter of 2020 of the divestment of its Midstream interests to Hilcorp Energy announced in 2019. As part of this transaction
impairments of $1,002 million were recognized in 2020. bp retained the decommissioning liability relating to its interest in TAPS which will be partially offset by a 30% reimbursement of costs incurred from Hilcorp.
In Canada bp is focused on pursuing offshore exploration opportunities and its Sunrise Oil Sands operations. We have offshore exploration licences in Nova Scotia, Newfoundland and Labrador and the Canadian Beaufort Sea. In addition to Sunrise Oil Sands we hold interests in two further oil sands lease areas through the Terre de Grace partnership and the Pike Oil Sands joint operation«. In-situ steam-assisted gravity drainage (SAGD) technology is utilized in our existing oil sands operations, which uses the injection of steam into the reservoir to warm the bitumen so that it can flow to the surface through producing wells.
308
bp
Annual Report and Form 20-F 2020
«See Glossary
Additional disclosures
•The order issued by the government of Canada in 2019 prohibiting any work or activity authorized under the Canada Oil and Gas Operations Act on frontier lands that are situated in Canadian Arctic offshore waters remains in effect until 31 December 2021.
•During the
year, impairment charges of $865 million were recognized in respect of certain assets in Canada, primarily as a result of changes to the group's long-term price assumptions.
•Also during the year, exploration write-offs of $2,539 million were recognized in relation to certain assets in Canada following management's re-assessment of expectations to extract value from certain exploration prospects as a result of a review of the group's long-term strategic plan and changes in the group's long-term price assumptions. A $247-million write-off was also recognized in relation to a prepayment for the Pike access pipeline.
•On 29 October, bp confirmed oil discoveries at the Cappahayden and Cambriol prospects in the Flemish Pass basin (bp 40%), offshore Newfoundland.
In Mexico, we have interests in
two exploration joint operations in the Salina Basin with Equinor and Total, Block 1 (bp 33% and operator) and Block 3 (bp 33%), and in one exploration joint operation in the Sureste Basin with Total and Hokchi, a subsidiary of Pan American Energy Group (PAEG), Block 34 (bp 42.5% and operator).
South America
bp has upstream activities in Argentina, Brazil and Trinidad & Tobago and through PAEG, in Argentina, Bolivia and Uruguay.
In Argentina bp and Total are partners on a 50/50 basis in two offshore exploration concessions. Total is the operator.
In Brazil bp has interests in 22 exploration concessions across five basins.
•During the year, exploration write-offs of $2,141 million were recognized in relation to certain assets
in Brazil following management's re-assessment of expectations to extract value from certain exploration prospects as a result of a review of the group's long-term strategic plan and changes in the group's long-term price assumptions.
•In the Foz do Amazonas basin, Total's request for a license extension for blocks FZA-M-57, 86, 88, 125 and 127was approved by the Brazilian regulatory authorities. Following their resignation from operatorship in August, Total reached agreement in October to transfer its working interest in these blocks to Petrobras. This transfer was also approved by the regulatory authorities.
•In FZA-M-59 block, bp requested a two year license extension to May 2022 which was approved by the ANP in June, based on Resolution 708/2017. bp also transferred its operatorship of this block to Petrobras, and this was approved
by the ANP in October.
•bp reached an agreement to sell Itaipu and Wahoo exploration assets to PetroRio for $100 million to be paid in instalments from 2021 onwards; a further $40 million payment is contingent on pre-agreed conditions. The completion of this transaction is subject to the approval from the Brazilian regulatory authorities.
PAEG, a joint venture that is owned by bp (50%) and Bridas Corporation (50%), has activities mainly in Argentina and Mexico, but is also present in Uruguay and Bolivia.
•On 24 May, the Hokchi project in Mexico, operated by PAEG, achieved first oil, producing 1.2mboe/d in 2020.
In Trinidad & Tobago bp holds interests in exploration and production licences and production-sharing contracts« (PSCs)
covering 1.6 million acres offshore of the east and north-east coast. Facilities include 15 offshore platforms and two onshore processing facilities. Production comprises gas and associated liquids.
bp also holds interests in the Atlantic LNG facility. bp’s shareholding averages 39% across four LNG trains« with a combined capacity of approximately 15 million tonnes per annum. During 2020 we sold gas to trains 1, 2 and 3 and processed gas in train 4. Most of the LNG produced from bp gas supplied to trains 2, 3 and 4 is sold to third parties under long- term contracts.
•The Cassia Compression project, a new compression platform with a 1.2bcf/d capacity bridge-linked to the Cassia
B processing platform was expected to start up in 2021 but is delayed to 2022 as a result of COVID-19 impacting delivery lines.
•Impairment charges of $2,416 million were recognized in 2020 in respect of certain assets in Trinidad, primarily as a result of changes to the group's long-term price assumptions.
•bp holds a 30% interest in two deepwater blocks, Block 23(a) and TTDAA14, with BHP as the Operator holding a 70% interest. There were four successful exploration wells drilled in 2019 and appraisal work is ongoing on these discoveries.
•bp’s initial gas sales and LNG offtake arrangements for Atlantic LNG Train 1 ended in September 2018. Subsequently, short term gas sales and LNG offtake arrangements were established and rolled over up until December 2020, with bp
lifting the majority of the LNG produced. The National Gas Company of Trinidad & Tobago (NGC) has agreed to fund the operating cost of Train 1 up to the end of December 2021 for the right but not the obligation to supply gas into Train 1 and offtake 100% of the resultant LNG.
•On 28 September, BP Trinidad and Tobago LLC started up the Galeota expansion project in Trinidad. The project comprises a new produced water handling facility, a new flare system, relocation of the control room away from production and upgrades to the existing condensate stabilization facility.
•bp is operator of the Manakin Block which was discovered in 1998 and is a cross border reservoir field with the Venezuelan reservoir, Cocuina. Manakin declared commerciality in January 2018 however cross border discussions have not progressed due to the US sanctions.
Africa
bp’s upstream activities in Africa are located in Algeria, Angola, Côte d'Ivoire, Egypt, The Gambia, Libya, Mauritania, São Tomé & Príncipe and Senegal. bp's interest in Madagascar was relinquished in 2020.
In Algeria bp, Sonatrach and Equinor are partners in the In Salah (bp 33.15%) and In Amenas (bp 45.89%) non-operated joint ventures that supply gas to the domestic and European markets.
In Angola, bp owns an interest in five major deepwater offshore licences and is operator in two of these, Blocks 18 and 31, that are producing. We also have an equity interest in the Angola LNG plant (bp 13.6%).
•During the year, exploration write-offs of $832 million were recognized in relation to certain assets in Angola following
management's re-assessment of expectations to extract value from certain exploration prospects as a result of a review of the group's long-term strategic plan and changes in the group's long-term price assumptions.
•Also during the year, impairment charges of $316 million were recognized in relation to certain assets in Angola, primarily as a result of changes to the group's long-term price assumptions.
•Development progressed at the Total-operated Zinia 2 deep offshore development project in Block 17 (bp 15.84%) and first production is expected in 2021.
•During the year, construction activity started at the Platina project in Block 18, with first production expected in 2022.
•Following the signing of
an agreement in December 2019 by bp and its partners with the Agência Nacional de Petróleo, Gás e Biocombustíveis (ANPG), to extend the production-sharing agreement« (PSA) for Block 17 until 2045, all conditions precedent relating to the agreement were met in the second quarter of 2020 and the new agreement became effective on 1 April 2020. Under the agreement the state-owned company Sonangol acquired a 5% equity interest in the block on the effective date with a further 5% to be transferred in 2036.
• In June 2019, bp and the contractor group signed an agreement with ANPG, extending the PSA for Block 15 until 2032. Under the agreement Sonangol acquired a 10% equity interest in the block, reducing bp’s interest from 26.67% to 24%. All conditions precedent relating to the agreement were met on 27 January 2020 and the new agreement became effective as
from 1 October 2019.
«See Glossary
bp Annual Report and Form 20-F 2020
309
•In December 2018, bp and the contractor
group signed an agreement with ANPG, extending the Block 18 PSA until 2032. Under the agreement, effective from 1 July 2020, Sonangol acquired an 8% equity interest in the block, reducing bp’s interest from 50% to 46%. All conditions precedent relating to the agreement were met on 17 December 2020.
In Côte d’Ivoire, bp has interests in five offshore oil blocks with Kosmos Energy (KE) under agreements with the government of Côte d'Ivoire and the state oil company Société Nationale d'Operations Pétrolières de la Côte d'Ivoire (PETROCI) (bp 45%).
In Egypt, bp and its partners currently produce 60% of Egypt’s gas production.
•During the year, exploration write-offs of $952 million were recognized in relation to certain assets in Egypt following management's re-assessment of expectations to extract value from certain
exploration prospects as a result of a review of the group's long-term strategic plan and changes in the group's long-term price assumptions.
•In July, bp confirmed the Bashrush gas discovery, located offshore Egypt in the North El Hammad concession (bp 37.5%).
•On 16 September, bp confirmed a gas discovery with the Nidoco NW-1 exploratory well in the Abu Madi West development lease, offshore Egypt (bp 25%).
•On 26 October bp announced the start-up of gas production from the Qattameya gas field in the North Damietta offshore concession (bp 100%). Qattameya, whose discovery was announced in 2017, is located approximately 45 km west of the Ha’py platform and is tied back to the Ha’py and Tuart field development via a new 50km pipeline.
•Work
on the West Nile Delta Raven project (BP 82.75%) is almost complete, with start up expected in the first quarter of 2021. Raven is the third project in North Alexandria and West Mediterranean deepwater offshore blocks.
In the Gambia, bp has a 90% interest in offshore block A1 with the state oil company, Gambia National Petroleum Corporation.
In Libya, bp partners with the Libyan Investment Authority (LIA) in an exploration and production sharing agreement (EPSA) to explore acreage in the onshore Ghadames and offshore Sirt basins (bp 85%). bp wrote off all balances associated with the Libya EPSA in 2015.
•bp, LIA and Eni continue to work with the NOC towards Eni acquiring a 42.5% interest in the bp-operated EPSA in Libya. On completion, Eni would become operator of the EPSA. The companies are continuing to work together
to finalize and complete all agreements.
In Mauritania and Senegal, bp has a 62% participating interest in the C8, C12 and C13 exploration blocks in Mauritania and a 60% participating interest in the Cayar Profond Offshore and St Louis Profond Offshore exploration blocks in Senegal. We relinquished our interest in the C6 exploration block in October. Together the remaining blocks cover approximately 19,700 square kilometres. For the Greater Tortue Ahmeyin (GTA) Unit across the border of Mauritania and Senegal, bp has a 56% participating interest.
The Phase 1 construction activity for the GTA major project« was severely affected by COVID-19 and the 2020 weather window for installation works was not met resulting in a delay to start up of around one year. A force majeure (FM) notice was issued under the lease and operate agreement with
Golar LNG over the provision of a floating liquified natural gas vessel, where due to the FM event the lessee was not able to meet the connection date. On 1 October, bp confirmed force majeure was lifted on the project.
•During the first quarter, bp executed a gas sale and purchase agreement with partners in the Greater Tortue Ahmeyim (GTA) project.
•During the year, impairment charges and an exploration write-off totalling $2,260 million were recognized in respect of certain assets in the region, primarily as a result of changes to the group's long-term price assumptions.
In Madagascar, during the second quarter, following management's re-assessment of expectations to extract value from certain exploration prospects as a result of a review of the group's long-term strategic plan and changes
in the group's long-term price assumptions, bp relinquished
its interest in three PSCs (the fourth was relinquished in February 2020) for exploration licences situated offshore northwest Madagascar, under agreements with the government of Madagascar represented by Office des Mines Nationales et des Industries Stratégiques (OMNIS) (bp 100%).
In São Tomé & Príncipe, bp is operator in two offshore blocks under PSAs with Shell who acquired the interests of KE in December 2020, and the state oil company Agencia Nacional do Petroleo (bp 50%).
Asia
bp has activities in Abu Dhabi, Azerbaijan, China, India, Indonesia, Iraq, Kuwait, Oman and Russia.
In China we have a 30% equity stake in the Guangdong LNG regasification
terminal and trunkline project with a total storage capacity of 640,000 cubic metres. The project is supplied under a long-term contract with Australia’s North West Shelf venture (bp 16.67%).
In Azerbaijan, bp operates two PSAs, Azeri-Chirag-Gunashli (ACG) (bp 30.37%) and Shah Deniz (bp 28.83%) and also holds a number of other exploration leases.
•Naftiran Intertrade Co Ltd (NICO), a subsidiary of the National Iranian Oil Company, holds a 10% interest in the Shah Deniz joint venture. For information on the exclusion of this project from EU and US trade sanctions, or exemptions from such trade sanctions in relation to this project, see International trade sanctions on page 325.
•During the year, impairment
charges of $537 million were recognized in respect of certain assets in the region, primarily as a result of changes to the group's long-term price assumptions.
•In January 2020 bp announced that drilling of the first well on the Shafag-Asiman offshore block had commenced. The drilling of the SAX01 well continued in 2020 and we expect it to reach the target depth in the first half of 2021.
bp holds a 30.1% interest in and operates the Baku-Tbilisi-Ceyhan oil pipeline. The 1,768-kilometre pipeline transports oil from the bp-operated ACG oilfield and gas condensate from the Shah Deniz gas field in the Caspian Sea, along with other third-party oil, to the eastern Mediterranean port of Ceyhan. The pipeline has a capacity of 1mmboe/d, with an average throughput in 2020 of 570mboe/d.
bp (as operator of Azerbaijan International
Operating Company) also operates the Western Route Export Pipeline that transports ACG oil to Supsa on the Black Sea coast of Georgia, with an average throughput of 85mboe/d in 2020.
bp holds a 28.83% interest in and performs some operations for the 693 kilometre South Caucasus Pipeline. The pipeline takes gas from Azerbaijan through Georgia to the Turkish border and has a capacity of 440mboe/d (including expansion), with average throughput in 2020 of 210mboe/d.
bp also holds a 12% interest in the Trans Anatolian Natural Gas Pipeline (TANAP). In the first phase, which commenced in 2018, gas from Shah Deniz is transported to Eskisehir in Turkey. The capacity of the pipeline during the first phase is 100mboe/d and the average throughput in 2020 was 80mboe/d. The second phase takes gas further to TANAP's connection with the Trans Adriatic Pipeline (TAP) at the Turkey-Greece border. bp
has a 20% interest in TAP, that takes gas through Greece and Albania into Italy. Commercial deliveries of gas via TAP commenced at the end of 2020.
In Oman bp operates Block 61, the largest tight gas« development in the Middle East (bp 60%), and is a 50% owner in Block 77.
•The Block 77 Exploration and PSA was approved by Royal Decree in the first quarter of 2020, with a plan to process seismic and drill one exploration well within the next three years. ENI (50%) is operator during the exploration phase and bp will be the operator of any potential development.
•On 12 October, bp announced production had begun from the Block 61 Phase 2 Ghazeer gas field, around 33 months after bp and its partners approved the development. bp brought the project
online ahead of the original planned start-up in early 2021, and under budget.
•On 1 February 2021 bp announced that it had agreed to sell a 20% participating interest in Block 61 to PTT Exploration and Production
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Additional disclosures
Public Company Limited (PTTEP) of Thailand for a total consideration of $2.6 billion. Following completion of the sale, which is subject to Royal Decree, bp will remain operator of the block with a 40% interest.
In Abu Dhabi, bp holds a 10% interest in the ADNOC Onshore concession. We also have a 10% equity shareholding in ADNOC LNG and a 10% shareholding in the shipping company NGSCO. ADNOC LNG supplied approximately 5.69 million tonnes of LNG (0.748bcfe/d regasified) in 2020. Our interest in the ADNOC Onshore concession
expires at the end of 2054.
In 2016 bp signed an enhanced technical service agreement for south and east Kuwait conventional oilfields, which includes the Burgan field, with Kuwait Oil Company. Delivery of the 2019-2020 plan was above target performance and implementation of the 2020-21 plan is underway.
In India we have a participating interest in two oil and gas PSAs (KG D6 33.33% and NEC25 33.33%), and one oil and gas block under a Revenue Sharing Contract (KG-UDWHP-2018/1 40%), all operated by Reliance Industries Limited (RIL). We also have a 50% stake in India Gas Solutions Private Limited, a joint venture with RIL, for the sourcing and marketing of gas in India.
•On 3 February, bp and RIL confirmed that they had completed
the safe cessation of production in a planned manner, from the D1 D3 field in Block KG D6, off the east coast of India (bp 33.33%).
•During the year, impairment charges of $1,313 million were recognized in respect of certain assets in India, primarily as a result of changes to the group's long-term price assumptions.
•Also during the year, exploration write-offs of $333 million were recognized in relation to certain assets in India following management's re-assessment of expectations to extract value from certain exploration prospects as a result of a review of the group's long-term strategic plan and changes in the group's long-term price assumptions.
•On 18 December, bp and RIL announced the start of gas production from R-Series, the first of the three projects in
Block KG D6. The other two projects (Satellites Cluster and MJ) are under development with first gas production phased over 2021-2022.
In Indonesia bp successfully completed the purchase of a 30% non-operated working interest in the Andaman II PSC from KrisEnergy in April. Andaman II is a deep-water block covering 7,400 square kilometres area in the North Sumatra basin, offshore from Aceh. Other interest holders are Premier Oil (40%, operator) and Mubadala Petroleum (30%).
In Iraq bp holds a 47.6% working interest and is the lead contractor in the Rumaila technical service contract in southern Iraq. The technical services contract runs to December 2034. Rumaila is one of the world’s
largest oil fields, comprising five producing reservoirs. bp's activities have not been materially impacted by the continued political instability and public protests which have occurred in 2020.
In Russia in addition to its interest in Rosneft as detailed on page 320, bp holds a 20% interest in Taas-Yuryakh Neftegazodobycha (Taas) together with Rosneft (50.1%) and a consortium comprising Oil India Limited, Indian Oil Corporation Limited and Bharat PetroResources Limited (29.9%). Taas is developing the Srednebotuobinskoye oil and gas condensate field in East Siberia. Also with Rosneft, we hold a 49% interest in Kharampurneftegaz LLC (Kharampur) to develop subsoil resources within the Kharampurskoe and Festivalnoye licence areas in Yamalo-Nenets. Rosneft (51%) and bp (49%) jointly own Yermak Neftegaz LLC (Yermak), which conducts onshore exploration in the West Siberian and Yenisei-Khatanga basins and currently holds six exploration
and production licences.
•During the year bp received $86 million of dividends net of withholding taxes and $51 million of distribution of paid in capital from Taas.
Australasia
bp has activities in Australia and Eastern Indonesia.
In Australia bp is one of seven participants in the North West Shelf (NWS) venture, which has been producing LNG, pipeline gas, condensate, LPG and oil since the 1980s. Six partners (including bp) hold an equal 16.67% interest in the gas infrastructure and an equal 15.78% interest in the gas and condensate reserves, with a seventh partner owning the remaining 5.32%. bp also has a 16.67% interest in some of the NWS oil reserves and related infrastructure. The NWS venture is currently the largest single
source supplier to the domestic market in Western Australia and one of the largest LNG export projects in the region, with five LNG trains in operation. bp’s net share of the capacity of NWS LNG trains 1-5 is 2.7 million tonnes of LNG per year.
bp is also one of five participants in the Browse LNG venture (operated by Woodside) and holds a 17.33% interest.
•The Browse joint venture participants continue to progress the development of Browse by connecting it via a 900km pipeline to the NWS Venture's Karratha Gas Plant.
In Papua Barat, Eastern Indonesia, bp operates the Tangguh LNG plant (bp 40.22%). The asset currently comprises 16 producing wells, two offshore platforms, two pipelines and an LNG plant with two production trains. It has a total capacity of 7.6 million tonnes of LNG per annum. Tangguh supplies LNG
to customers in Indonesia, Mexico, China, South Korea, and Japan through a combination of long, medium and short-term contracts.
The Tangguh expansion project comprises a third LNG processing train, two offshore platforms, 10 new production wells, an expanded LNG loading facility, and supporting infrastructure. The project will add 3.8 million tonnes per annum (mtpa) of production capacity to the existing facility, bringing total plant capacity to 11.4mtpa. Due to COVID-19 and the need to relocate personnel from the remote project, the start-up is expected to be delayed to 2022.
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bp Annual Report and Form 20-F 2020
311
Oil and natural gas
Resource progression
bp manages its hydrocarbon resources in three major categories: prospect inventory, contingent resources and reserves. When a discovery is made, volumes usually transfer from the prospect inventory to the contingent resources category. The contingent resources move through various sub-categories as their technical and commercial maturity increases through appraisal activity.
At
the point of final investment decision, most proved reserves will be categorized as proved undeveloped (PUD). Volumes will subsequently be recategorized from PUD to proved developed (PD) as a consequence of development activity. When part of a well’s proved reserves depends on a later phase of activity, only that portion of proved reserves associated with existing, available facilities and infrastructure moves to PD. The first PD bookings will typically occur at the point of first oil or gas production. Major development projects typically take one to five years from the time of initial booking of PUD to the start of production. Changes to proved reserves bookings may be made due to analysis of new or existing data concerning production, reservoir performance, commercial factors and additional reservoir development activity.
Volumes can also be added or removed from our portfolio through acquisition or divestment of properties
and projects. When we dispose of an interest in a property or project, the volumes associated with our adopted plan of development for which we have a final investment decision will be removed from our proved reserves upon completion of the transaction. When we acquire an interest in a property or project, the volumes associated with the existing development and any committed projects will be added to our proved reserves if bp has made a final investment decision and they satisfy the SEC’s criteria for attribution of proved status. Following the acquisition, additional volumes may be progressed to proved reserves from non-proved reserves or contingent resources.
Non-proved reserves and contingent resources in a field will only be recategorized as proved reserves when all the criteria for attribution of proved status have been met and the volumes are included in the business plan and scheduled for development, typically within
five years. bp will only book proved reserves where development is scheduled to commence after more than five years, if these proved reserves satisfy the SEC’s criteria for attribution of proved status and bp management has reasonable certainty that these proved reserves will be produced.
At the end of 2020 bp had material volumes of proved undeveloped reserves held for more than five years in Russia, Trinidad, Gulf of Mexico, Azerbaijan, Indonesia and the North Sea. These are part of ongoing infrastructure-led development activities for which bp has a historical track record of completing comparable projects in these countries. We have no proved undeveloped reserves held for more than five years in our onshore US developments.
In each case the volumes are being progressed as part of an adopted development plan where there are physical limits to the development timing such as infrastructure
limitations, contractual limits including gas delivery commitments, late life compression and the complex nature of working in remote locations, or where there are significant commitments on delivery to the relevant authority.
Over the past five years, bp has annually progressed a weighted average 17% (19% for 2019 five-year average) of our group proved undeveloped reserves (including the impact of disposals and price acceleration effects in PSAs) to proved developed reserves. This equates to a turnover time of six years.
Proved reserves as estimated at the end of 2020 meet bp’s criteria for project sanctioning and SEC tests for proved reserves. We have not halted or changed our commitment to proceed with any material project to which proved undeveloped reserves have been attributed.
In 2020 we progressed 897 mmboe of proved undeveloped
reserves (512 mmboe for our subsidiaries« alone) to proved developed reserves through ongoing investment in our subsidiaries’ and equity-accounted entities’ upstream development activities. Total development expenditure, excluding midstream activities, was $11,041 million in 2020 ($7,650 million for subsidiaries and $3,391 million for equity-accounted
entities). The major areas with progressed volumes in 2020 were Russia, US, Egypt and Oman. Revisions of previous estimates for proved undeveloped reserves are due to changes relating to field performance, well results
or changes in commercial conditions including price impacts. The following tables describe the changes to our proved undeveloped reserves position through the year for our subsidiaries and equity-accounted entities and for our subsidiaries alone.
Proved developed reserves reclassified as undeveloped
173
Progressed to proved developed reserves by development activities (e.g. drilling/completion)
(512)
Proved undeveloped reserves at 31 December 2020
3,673
a Because of rounding, some totals may not agree exactly with the sum of their component
parts.
bp bases its proved reserves estimates on the requirement of reasonable certainty with rigorous technical and commercial assessments based on conventional industry practice and regulatory requirements. bp only applies technologies that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. bp applies high-resolution seismic data for the identification of reservoir extent and fluid contacts only where there is an overwhelming track record of success in its local application. In certain cases bp uses numerical simulation as part of a holistic assessment of recovery factor for its fields, where these simulations have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated
or in an analogous formation. In certain deepwater fields bp has booked proved reserves before production flow tests are conducted, in part because of the significant safety, cost and environmental implications of conducting these tests. The industry has made substantial technological improvements in understanding, measuring and delineating reservoir properties without the need for flow tests. To determine reasonable certainty of commercial recovery, bp employs a general method of reserves assessment that relies on the integration of three types of data:
•well data used to assess the local characteristics and conditions of reservoirs and fluids
•field scale seismic data to allow the interpolation and extrapolation of these characteristics outside the immediate area of the local well control
•data
from relevant analogous fields.
Well data includes appraisal wells or sidetrack holes, full logging suites, core data and fluid samples. bp considers the integration of this data in certain cases to be superior to a flow test in providing understanding of overall reservoir performance. The collection of data from logs, cores, wireline formation testers, pressures and fluid samples calibrated to each other and to the seismic data can allow reservoir properties to be
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Additional disclosures
determined over a greater volume than the localized volume of investigation associated with a short-term flow test. There is a strong track record of proved reserves recorded using these methods, validated by actual production levels.
Governance
bp’s centrally controlled process for proved reserves
estimation approval forms part of a holistic and integrated system of internal control. It consists of the following elements:
•Accountabilities of certain officers of the group to ensure that there is review and approval of proved reserves bookings independent of the operating business and that there are effective controls in the approval process and verification that the proved reserves estimates and the related financial impacts are reported in a timely manner.
•Capital allocation processes, whereby delegated authority is exercised to commit to capital projects that are consistent with the delivery of the group’s business plan. A formal review process exists to ensure that both technical and commercial criteria are met prior to the commitment of capital to projects.
•Group
audit, whose role is to consider whether the group’s system of internal control is adequately designed and operating effectively to respond appropriately to the risks that are significant to bp.
•Approval hierarchy, whereby proved reserves changes above certain threshold volumes require immediate review and all proved reserves require annual central authorization and have scheduled periodic reviews. The frequency of periodic review ensures that 100% of the bp proved reserves base undergoes central review every three years.
bp’s vice president of segment reserves is the individual primarily responsible for overseeing the preparation of the reserves estimate. He has more than 27 years of diversified industry experience in reserves estimation with the past 2 years managing the governance and compliance. He is a past Chairman of the Society of Petroleum Engineers
(Russia & Caspian) and a member of the United Nations Economic Commission for Europe Expert Group on Resource Management.
No specific portion of compensation bonuses for senior management is directly related to proved reserves targets. Additions to proved reserves is one of several indicators by which the performance of the Upstream segment is assessed by the remuneration committee for the purposes of determining compensation bonuses for the executive directors. Other indicators include a number of financial and operational measures.
bp’s variable pay programme for the other senior managers in the Upstream segment is based on individual performance contracts. Individual performance contracts are based
on agreed items from the business performance plan, one of which, if chosen, could relate to proved reserves.
Compliance
International Financial Reporting Standards (IFRS) do not provide specific guidance on reserves disclosures. bp estimates proved reserves in accordance with SEC Rule 4-10 (a) of Regulation S-X and relevant Compliance and Disclosure Interpretations (C&DI) and Staff Accounting Bulletins as issued by the SEC staff.
By their nature, there is always risk involved in the ultimate development and production of proved reserves including, but not limited to: final regulatory approval; the installation of new or additional infrastructure, as well as changes in oil and gas prices; changes in operating and development costs; and the continued availability of additional development capital. All the group’s proved reserves held
in subsidiaries and equity-accounted entities are estimated by the group’s petroleum engineers or by independent petroleum engineering consulting firms and then assured by the group’s petroleum engineers.
DeGolyer & MacNaughton (D&M), an independent petroleum engineering consulting firm, has estimated the net proved crude oil, condensate, natural gas liquids (NGLs) and natural gas reserves, as of 31 December 2020, of certain properties owned by Rosneft as part of our equity-accounted proved reserves. The properties evaluated by D&M account for 100% of Rosneft’s net proved reserves as of 31 December 2020. The net proved reserves estimates prepared by D&M were prepared in accordance with the reserves definitions of Rule 4-10(a)(1)-(32) of
Regulation
S-X. All reserves estimates involve some degree of uncertainty. bp has filed D&M’s independent report on its reserves estimates as an exhibit to this Annual Report on Form 20-F filed with the SEC.
Netherland, Sewell & Associates (NSAI), an independent petroleum engineering consulting firm, has estimated the net proved crude oil, condensate, natural gas liquids (NGLs) and natural gas reserves, as of 31 December 2020, of certain properties owned by bp in the US Lower 48. The properties evaluated by NSAI account for 100% of bp’s net proved reserves in the US Lower 48 as of 31 December 2020. The net proved reserves estimates prepared by NSAI were prepared in accordance with the reserves definitions of Rule 4-10(a)(1)-(32) of Regulation S-X. All reserves estimates involve some degree of uncertainty. bp has filed NSAI’s independent report on its reserves estimates as an exhibit to this Annual Report on Form 20-F filed with
the SEC.
Our proved reserves are associated with both concessions (tax and royalty arrangements) and agreements where the group is exposed to the upstream risks and rewards of ownership, but where our entitlement to the hydrocarbons is calculated using a more complex formula, such as with PSAs. In a concession, the consortium of which we are a part is entitled to the proved reserves that can be produced over the licence period, which may be the life of the field. In a PSA, we are entitled to recover volumes that equate to costs incurred to develop and produce the proved reserves and an agreed share of the remaining volumes or the economic equivalent. As part of our entitlement is driven by the monetary amount of costs to be recovered, price fluctuations will have an impact on both production volumes and reserves.
We disclose our share of proved reserves held in equity-accounted entities
(joint ventures« and associates«), although we do not control these entities or the assets held by such entities.
bp’s estimated net proved reserves and proved reserves replacement
92% of our total proved reserves of subsidiaries at 31 December 2020 were held through joint operations« (91% in 2019), and 31% of the proved reserves were held through such joint operations where we were not the operator (28% in 2019).
Estimated net proved reserves of crude oil at 31 December 2020a b c
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability
to make lifting and sales arrangements independently, and include non-controlling interests in consolidated operations. We disclose our share of reserves held in joint ventures and associates that are accounted for by the equity method although we do not control these entities or the assets held by such entities.
b The 2020 marker prices used were Brent« $41.31/bbl (2019 $62.74/bbl and 2018 $71.43/bbl) and Henry Hub« $1.94/mmBtu (2019 $2.58/mmBtu and 2018 $3.10/mmBtu).
c Includes condensate.
d All of the reserves in Canada are bitumen.
e Includes 11 million barrels of liquids in respect of
the 30% non-controlling interest in BP Trinidad and Tobago LLC.
f Includes 405 million barrels in respect of the non-controlling interest in Rosneft, including 19mmboe held through bp’s interests in Russia other than Rosneft.
g Includes 1,059 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
h Includes 1,640 billion cubic feet of natural gas in respect of the 10.01% non-controlling interest in Rosneft including 614 billion cubic feet held through bp’s interests in Russia other than Rosneft.
i Includes 264 million barrels of oil equivalent associated with Assets Held for Sale in Oman.
Because
of rounding, some totals may not agree exactly with the sum of their component parts.
Proved reserves replacement
Total hydrocarbon proved reserves at 31 December 2020, on an oil equivalent basis including equity-accounted entities, decreased by 7% compared with 31 December 2019. Natural gas represented about 41% (47% for subsidiaries and 36% for equity-accounted entities) of these reserves. The change includes a net decrease from acquisitions and disposals of 1,069mmboe (decrease of 1,072mmboe within our subsidiaries and increase of 3mmboe within our equity-accounted entities). Acquisition and divestment activity occurred
in our equity-accounted entities in Russia, and divestment activity in our subsidiaries in the US including Alaska.
The proved reserves replacement ratio« is the extent to which production is replaced by proved reserves additions. This ratio is expressed in oil equivalent terms and includes changes resulting from revisions to previous estimates, improved recovery, and extensions and discoveries. For 2020, the proved reserves replacement ratio excluding acquisitions and disposals was 78% (67% in 2019 and 100% in 2018) for subsidiaries and equity-accounted entities, 47% for subsidiaries alone and 127% for equity-accounted
entities alone. There was a net decrease (373mmboe) of reserves due to lower gas and oil prices within the US, North Sea and Angola partly offset by increases related to price in some of our PSAs in Iraq and Azerbaijan.
In 2020 net additions to the group’s proved reserves (excluding production and sales and purchases of reserves-in-place) amounted to 1,006mmboe (380mmboe for subsidiaries and 626mmboe for equity-accounted entities), through revisions to previous estimates including price, improved recovery from, and extensions to, existing fields and discoveries of new fields. The subsidiary additions were through improved recovery from, and extensions to, existing fields and discoveries of new fields where they represented a mixture of proved developed and proved undeveloped reserves. Volumes added in 2020 principally resulted from
the application of conventional technologies and extensions of field size by development drilling. The principal proved reserves additions in our subsidiaries by region were in the US, Oman, Azerbaijan and Angola. The principal reserves additions in our equity-accounted entities were in Rosneft and Pan American Energy Group.
16% of our proved reserves are associated with PSAs. The countries in which we produced under PSAs in 2020 were Algeria, Angola, Azerbaijan, Egypt, India, Indonesia and Oman. In addition, the technical service contract (TSC) governing our investment in the Rumaila field in Iraq functions as a PSA.
The group holds no licences due to expire within the next three years that would have
a significant impact on bp’s reserves or production. bp holds reserves classified as Assets held for sale in Oman.
For further information on our reserves see page 238.
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Additional
disclosures
bp’s net production by country – crude oila and natural gas liquids
b Production excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently.
c In 2020, bp disposed of its Alaska interests and certain Lower 48 onshore interests in the US. In 2019, bp completed the sale of its interest in the Gulf of Suez Petroleum Company (GUPCO) in Egypt and certain US assets in Lower 48 onshore and disposed of its interests in the Gulf of Mexico Santiago and Santa Cruz wells. In 2018, bp acquired various interests in the Permian Basin, Eagle Ford and Haynesville Shales in Lower 48 onshore as a result of the acquisition of BHP’s US unconventional assets, increased its interest in the Clair asset in the UK North Sea, and acquired an interest
in LLC Kharampurneftegaz in Russia, and in certain US offshore assets. It also disposed of its interests in the Greater Kuparuk Area in Alaska, the Magnus field in the UK North Sea, and in certain other assets in the UK North Sea and US onshore assets.
d Volumes relate to six bp-operated fields within ETAP. bp has no interests in the remaining three ETAP fields, which are operated by Shell.
e All of the production from Canada in Subsidiaries is bitumen.
f Includes production in respect of the non-controlling interest in Rosneft, including production held through bp’s interests in Russia other than Rosneft.
g Includes
3 net mboe/d of NGLs from processing plants in which bp has an interest (2019 3mboe/d and 2018 3mboe/d).
Because of rounding, some totals may not agree exactly with the sum of their component parts.
a Production excludes royalties due to others whether
payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently.
b In 2020, bp disposed of its Alaska interests and certain Lower 48 onshore interests in the US. In 2019, bp completed the sale of its interest in the Gulf of Suez Petroleum Company (GUPCO) in Egypt and certain US assets in Lower 48 onshore and disposed of its interests in the Gulf of Mexico Santiago and Santa Cruz wells. In 2018, bp acquired various interests in the Permian Basin, Eagle Ford and Haynesville Shales in Lower 48 onshore as a result of the acquisition of BHP’s US unconventional assets, increased its interest in the Clair asset in the UK North Sea, and acquired an interest in LLC Kharampurneftegaz in Russia, and in certain US offshore assets. It also disposed of its interests in the Greater Kuparuk Area in
Alaska, the Magnus field in the UK North Sea, and in certain other assets in the UK North Sea and US onshore assets.
c Natural gas production volumes exclude gas consumed in operations within the lease boundaries of the producing field, but the related reserves are included in the group’s reserves.
d Includes production in respect of the non-controlling interest in Rosneft, including production held through bp’s interests in Russia other than Rosneft.
Because of rounding, some totals may not agree exactly with the sum of their component parts.
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Additional disclosures
The following tables provide additional data and disclosures in relation to our oil and gas operations.
Average sales price per unit of production (realizations«)a
a
Units of production are barrels for liquids and thousands of cubic feet for gas. Realizations include transfers between businesses, except in the case of Russia.
b An amendment has been made to 2019 and 2018 to align with the disclosures for oil and natural gas exploration and production activities.
c Includes condensate.
d In certain countries it is common for equity-accounted entities’ agreements to include pricing clauses that require selling a significant portion of the entitled production to local governments or markets at discounted prices.
e Natural gas liquids for Russia are included in crude oil.
f Units of production are
barrels for liquids and thousands of cubic feet for gas. Amounts do not include ad valorem and severance taxes.
«See Glossary
bp Annual Report and Form 20-F 2020
317
Additional
information for Downstream
Refinery throughputsa b
thousand barrels per day
2020
2019
2018
US
693
737
703
Europe
742
787
781
Rest
of the world
192
225
241
Total
1,627
1,749
1,725
%
Refining availability«
96.0
94.9
95.0
a
This does not include bp’s interest in Pan American Energy Group.
b Refinery throughputs reflect crude oil and other feedstock volumes.
Sales volume
thousand barrels per day
2020
2019
2018
Marketing
salesa
2,275
2,727
2,736
Trading/supply salesb
3,026
3,268
3,194
Total refined product sales
5,301
5,995
5,930
Crude oilc
2,397
2,713
2,624
Total
7,698
8,708
8,554
a
Marketing sales include branded and unbranded sales of refined fuel products and lubricants to business-to-business and business-to-consumer customers, including service station dealers, jobbers, airlines, small and large resellers such as hypermarkets, and the military.
b Trading/supply sales are fuel sales to large unbranded resellers and other oil companies.
c Crude oil sales relate to transactions executed by our integrated supply and trading function, primarily for optimizing crude oil supplies to our refineries and in other trading. 2020 includes 44 thousand barrels per day relating to revenues reported by the Upstream segment.
Sales volumes reported in the table above are for those transactions that are reported as gross sales in the group income statement.
From 2021, certain sales and purchase transactions that have previously been reported gross in the group income statement will be reported on a net basis in the income statement. The volumes for 2020 transactions that would have been subject to potential netting in the income statement but are presented gross in this table are approximately 2,063 thousand barrels a day of crude oil, 2,613 thousand barrels a day of trading/supply sales, and 126 thousand barrels a day of marketing sales.
Retail sitesa
Number
of bp-branded retail sites
2020
2019
2018
US
7,300
7,200
7,200
Europe
8,200
8,200
8,200
Rest of the world
4,800
3,500
3,300
Total
20,300
18,900
18,700
a
Reported to the nearest 100. Includes sites operated by dealers, jobbers, franchisees, brand licensees or JV partners, under the bp brand. These may move to and from the bp brand as their fuel supply agreement or brand licence agreement expires and are renegotiated in the normal course of business. Retail sites are primarily branded bp, ARCO, Amoco, Aral and Thorntons, and also include sites in India through our Jio-bp JV.
Reconciliation of RC profit before interest and tax to gross margin for convenience, retail fuels and electrification
$
billion
2020
2019
RC profit before interest and tax for Downstream
3.4
6.5
Net (favourable) adverse impact of non-operating items« and fair value accounting effects«
(0.3)
(0.1)
Underlying RC profit before interest and tax for Downstream
3.1
6.4
Subtract
underlying RC profit (loss) for petrochemicals, refining and trading, and lubricants
1.0
3.9
Add back:
Fuels (excluding refining and trading) depreciation, depletion and amortization
1.0
1.0
Fuels (excluding refining and trading) production and manufacturing, distribution and administration expenses and adjusted for aviation, B2B and midstream gross margin
1.9
1.8
Adjusted
for earnings from equity-accounted entities in fuels (excluding refining and trading)
(0.2)
(0.3)
Gross margin for convenience, retail fuels and electrification«
4.8
5.0
Of which:
Convenience gross margin
1.3
1.2
Retail
fuels gross margin
3.5
3.7
Electrification gross margin
0.0
0.0
318
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Additional disclosures
Refinery capacity
The following tablea summarizes bp group’s interests in refineries and average daily crude distillation capacities as at 31 December 2020.
Crude
distillation capacitiesb
Fuels value chain
Country
Refinery
Group interestc
(%)
BP share thousand barrels per day
US
US North West
US
Cherry Point
100
251
US
East of Rockies
Whiting
100
440
Toledo
50
80
771
Europe
Rhine
Germany
Gelsenkirchen
100
265
Lingen
100
97
Netherlands
Rotterdam
100
390
Iberia
Spain
Castellón
100
110
862
Rest
of world
Australia
Australia
Kwinanad
100
152
New Zealand
New Zealand
Whangareief
10.1
34
Southern
Africa
South Africa
Durbane
50
90
276
Total bp share of capacity at 31 December 2020
1,909
a This does not include bp’s interest in Pan American Energy Group.
b
Crude distillation capacity is gross rated capacity, which is defined as the highest average sustained unit rate for a consecutive 30-day period under normal operational conditions.
c bp share of equity, which is not the same as bp share of processing entitlements.
d In the fourth quarter 2020, we announced plans to cease fuel production at our Kwinana Refinery and convert it to an import terminal.
e Indicates refineries not operated by bp.
f Reflects bp share of processing entitlement, which is not the same as bp share of equity.
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bp Annual Report and Form 20-F 2020
319
Additional information for Rosneft
About Rosneft
Rosneft is the largest oil company in Russia, with a strong portfolio of current and future opportunities. Russia has one of the largest and lowest-cost hydrocarbon resource bases in the world and its resources play an important role in long-term energy supply to the global economy.
Rosneft
is one of the largest publicly traded oil companies in the world based on hydrocarbon production volume. And it has a major resource base of hydrocarbons onshore and offshore, with assets in all of Russia’s key hydrocarbon regions and abroad. bp's share of Rosneft hydrocarbon production in 2020 was 1,098mboe/d, compared with 1,144mboe/d in 2019.
Rosneft is a member of the Methane Guiding Principles initiative that aims to reduce methane emissions along the natural gas value chain. It reaffirmed its commitment to the 17 UN Sustainable Development Goals and the core principles of the UN Global Compact.
Rosneft is the leading Russian refining company based on throughput. It owns and operates 13 refineries in Russia and holds stakes in three refineries in Germany, one in India and one in Belarus. Rosneft refinery throughput in 2020 was 2,103mb/d, compared with 2,236mb/d in 2019.
Downstream
operations include jet fuel, bunkering, bitumen and lubricants. Rosneft also owns and operates over 3,055 retail service stations in Russia and abroad. These includes Rosneft-branded sites, as well as bp-branded sites operating under a licensing agreement.
Rosneft’s largest shareholder is Rosneftegaz JSC (Rosneftegaz), which is wholly owned by the Russian government. At 31 December 2020, Rosneftegaz held 40.4% (2019: 50% plus one share) of the voting share capital of Rosneft.
2020 summary
bp remains committed to our strategic investment in Rosneft, while complying with all relevant sanctions.
bp’s two nominees, Bernard Looney and Bob Dudley, were elected to Rosneft’s board at Rosneft's annual general meeting (AGM) in June. Bob Dudley is a chairman of the Rosneft board’s Strategy and Sustainable
Development Committee. At the AGM, shareholders also approved a resolution to pay a dividend. bp received a payment of $480 million, after the deduction of withholding tax, in July.
On 30 April, Rosneft completed a transaction to transfer all of its interest and cease participation in its Venezuelan businesses to a company owned by the government of the Russian Federation. In consideration, it received shares equal to a 9.6% share of its own equity. The shares are held by a 100% subsidiary of Rosneft and accounted for as treasury shares. Rosneft also has an approved programme of share buybacks under which shares are being repurchased. Those shares are also accounted for as treasury shares.
bp retains 19.75% of the voting rights at meetings of Rosneft shareholders and continues to be entitled to dividends based on that shareholding. bp’s economic interest as of 31 December 2020, however,
has increased to 22.03% as a result of its indirect interest in the shares held by the subsidiaries of Rosneft. bp’s share of profit or loss of Rosneft reflects its economic interest.
On 14 December 2020, Rosneft announced the sale of a 49% stake in Krasgeonats to Equinor for approximately $550 million. Krasgeonats owns 12 licences for exploration and production in Eastern Siberia, including the recently launched North-Danilovskoye field.
On 28 December, Rosneft announced completion of the acquisition of 100% stakes in JSC Taimyrneftegaz and LLC Taimyrburservis, and the sale of a 10% interest in LLC Vostok Oil to Trafigura for Euro 7 billion.
In December, Rosneft announced that it has developed a 2035 Carbon Management Plan, a long-term framework
for its development in the context of transitioning to a low carbon economy, including management of climate risks and identification of opportunities related to future energy demand.
2020 marked the 10th anniversary of Rosneft’s participation in UN Global Compact, the world’s largest sustainability initiative. In 2020, Rosneft
presented its public statement regarding human rights and the Declaration on Human Rights for interacting with suppliers of goods, works and services.
In February 2021,Rosneft and bp signed a Strategic Collaboration Agreement focused on supporting carbon management and sustainability activities of both companies.
The agreement builds on bp’s longstanding strategic partnership with Rosneft and will explore opportunities for
new investment and collaboration in Russia across several key focus areas:
•Developing industry methodologies and standards on carbon management, including methane reduction initiatives and energy efficiency applications.
•Evaluating new projects in renewables, carbon capture and hydrogen.
•Assessing opportunities in the downstream including advanced fuels, natural forest sinks and carbon offset credits.
•Sustainable development and social investment, including biodiversity.
320
bp
Annual Report and Form 20-F 2020
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Additional disclosures
Environmental expenditure
$ million
2020
2019
2018
Operating
expenditure
531
511
501
Capital expenditure
241
468
449
Clean-ups
29
23
31
Additions
to environmental remediation provision
297
272
428
Increase (decrease) in decommissioning provision
(686)
1,045
137
Operating and capital expenditure on the prevention, control, treatment or elimination of air and water emissions and solid waste is often not incurred as a separately identifiable transaction. Instead, it forms part of a
larger transaction that includes, for example, normal operations and maintenance expenditure. The figures for environmental operating and capital expenditure in the table are therefore estimates, based on the definitions and guidelines of the American Petroleum Institute.
Environmental operating expenditure of $531 million in 2020 (2019 $511 million) showed an overall increase of 4%, with increases in BP Products and Shipping expenditure largely balanced out by a reduction in expenditure for BPX Energy.
Environmental capital expenditure of $241 million in 2020 was significantly down (2019 $468 million) largely due to decreased expenditure in the BPX Energy and BP Products North America business.
Clean-up costs were $29 million in 2020 (2019 $23 million) representing oil spill clean-up costs and other associated remediation and disposal costs.
The increase compared to 2019 results largely from increased expenditure in three businesses, namely BP Pipelines (North America), Alaska and Remediation Management.
In addition to operating and capital expenditure, we also establish provisions for future environmental remediation work. Expenditure against such provisions normally occurs in subsequent periods and is not included in environmental operating expenditure reported for such periods.
Provisions for environmental remediation are made when a clean-up is probable and the amount of the obligation can be reliably estimated. Generally, this coincides with the commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites.
The extent and cost of future environmental restoration, remediation and abatement programmes are inherently difficult to estimate.
They often depend on the extent of contamination, and the associated impact and timing of the corrective actions required, technological feasibility and bp’s share of liability. Though the costs of future programmes could be significant and may be material to the results of operations in the period in which they are recognized, it is not expected that such costs will be material to the group’s overall results of operations or financial position.
Additions to our environmental remediation provision was similar to prior years and also reflects scope reassessments of the remediation plans of a number of our sites in the US. The charge for environmental remediation provisions in 2020 included $8 million in respect of provisions for new sites (2019 $9 million and 2018 $8 million).
In addition, we make provisions on installation of our oil and gas producing assets and related pipelines
to meet the cost of eventual decommissioning. On installation of an oil or natural gas production facility, a provision is established that represents the discounted value of the expected future cost of decommissioning the asset.
In 2020, the net decrease in the decommissioning provision was due to a change in the discount rate and a change in cost estimate assumptions.
We undertake periodic reviews of existing provisions. These reviews take account of revised cost assumptions, changes in decommissioning requirements and any technological developments.
Provisions for environmental remediation and decommissioning are usually established on a discounted basis, as required by IAS 37 ‘Provisions, Contingent Liabilities and Contingent Assets’.
Further details of decommissioning and environmental provisions
appear in Financial statements – Note 23.
Regulation of the group’s business
Our businesses and operations are subject to the laws and regulations applicable in each country, state or other regional or local area in which they occur. These cover virtually all aspects of bp’s activities and include matters such as licence acquisition, production rates, royalties, environmental, health and safety protection, fuel specifications and transportation, trading, pricing, anti-trust, export, taxes, and foreign exchange.
Oil and gas contractual and regulatory framework
The terms and conditions of the leases, licences
and contracts under which our upstream oil and gas interests are held vary from country to country. These leases, licences and contracts are generally granted by or entered into with a government entity or state-owned or controlled company and are sometimes entered into with private property owners. Arrangements with governmental or state entities usually take the form of licences or production-sharing agreements« (PSAs), although arrangements with private entities and the US government entities are usually by lease.
Licences (or concessions) give the holder the right to explore for, develop and produce a commercial discovery. Under a licence, the holder bears the risk of exploration,
development and production activities and provides the financing for these operations. In principle, the licence holder is entitled to all production, minus any royalties that are payable in kind. A licence holder is generally required to pay production taxes or royalties, which may be in cash or in kind.
In certain countries, separate licences are required for exploration and production activities, and in some cases production licences are limited to only a portion of the area covered by the original exploration licence.
PSAs entered into with a government entity or state-owned or controlled company generally require bp (alone or with other contracting companies) to provide all the financing and bear the risk of exploration and production activities in exchange for a share of the production remaining after royalties, if any. Less typically, bp may explore for, develop and produce
hydrocarbons under a service agreement with the host entity in exchange for reimbursement of costs and/or a fee paid in cash rather than production.
bp frequently conducts its exploration and production activities in joint arrangements« or co-ownership arrangements with other international oil companies, state-owned or controlled companies and/or private companies. Conventionally, all costs, benefits, rights, obligations, liabilities and risks incurred in carrying out joint arrangement or co-ownership operations under a lease, licence or PSA are shared among the joint arrangement or co-owning parties according to agreed ownership interests among them. To the extent that any liabilities arise, whether to governments or third parties, or as between the joint arrangement parties or co-owners themselves, each joint arrangement party or co-owner will generally
be liable to meet these in proportion to its ownership interest. In many upstream operations, a party (known as the operator) will be appointed (pursuant to a joint operating agreement) to carry out day to-day operations on behalf of the joint arrangement or co-ownership. The operator is typically one of the joint arrangement parties or a co-owner and will carry out its duties either through its own staff, or by contracting out various elements to third-party contractors or service providers. bp acts as operator on behalf of joint arrangements and co-ownerships in a number of countries.
Frequently, work (including drilling and related activities) will be contracted out to third-party service providers. The relevant contract will specify the work, the remuneration, and typically the risk allocation between the parties. Depending on the
service to be provided, the contract may also contain provisions allocating risks and liabilities associated with pollution and environmental damage, damage to a well or hydrocarbon reservoirs and for claims from third parties or other losses. The allocation of those risks vary among contracts and are determined through negotiation between the parties.
«See Glossary
bp Annual Report and Form 20-F 2020
321
In general, bp incurs income tax on income generated from production activities (whether under a licence or PSA). In addition, depending on the area, bp’s production activities may be subject to a range of other taxes, levies and assessments, including special petroleum taxes and revenue taxes. The taxes imposed on oil and gas production profits and activities may be substantially higher than those imposed on other activities, for example in Abu Dhabi, Angola, Egypt, Norway, the UK, the US, Russia and Trinidad & Tobago.
Sustainable
finance
On 12 July 2020, elements of Regulation (EU) 2020/852 on the establishment of a framework to facilitate sustainable investment (Taxonomy Regulation) entered into force and form part of UK law pursuant to the European Union (Withdrawal) Act of 2018. The Taxonomy Regulation establishes a classification system for determining whether an economic activity is environmentally sustainable for the purposes of guiding investors in financial products which are marketed as promoting environmental objectives. Although the UK government has expressed its intention to retain the overall taxonomy framework and objectives as set forth in the Taxonomy Regulation, it is not yet clear to what extent UK law will align with elements of the Taxonomy Regulation which were not in effect as of the end of the Brexit transition period on 31 December 2020. bp may in the future be required to comply with the Taxonomy Regulation or any parallel
or similar legislation which may come into force in the UK.
Greenhouse gas regulation
In December 2015, nearly 200 nations at the United Nations climate change conference in Paris (COP21) agreed the Paris Agreement which aims to hold the increase in the global average temperature to well below 2°C above pre-industrial levels and to pursue efforts to limit the temperature increase to 1.5°C above pre-industrial levels. Signatories aim to reach global peaking of greenhouse gas (GHG) emissions as soon as possible and to undertake rapid reductions thereafter, so as to achieve a balance between human caused emissions and removals by sinks of GHGs in the second half of this century. The Paris Agreement commits all signatories to submit Nationally Determined Contributions (NDCs) (i.e. pledges or plans of climate action) and pursue domestic
measures aimed at achieving the objectives of their NDCs. Signatories are required to submit revised NDCs every five years, and the revised NDC’s are expected to be more ambitious with each revision. Global assessments of progress will occur every five years, starting in 2023.
Agreement of rules which could enable international carbon trading to assist in meeting NDCs, has been deferred to COP26 which is expected to take place in Glasgow, Scotland in November 2021. More stringent national and regional measures relating to the transition to a lower carbon economy, such as the UK's 2050 net zero carbon emissions commitment, can be expected in the future. These measures could increase bp’s production costs for certain products, increase compliance and litigation costs, increase demand for competing energy alternatives or products with lower-carbon intensity, and affect the sales and specifications of many of bp’s products. Further,
such measures could lead to constraints on production and supply and access to new reserves, particularly due to the long term nature of many of bp’s projects. Certain current and announced GHG measures and developments potentially affecting bp’s businesses in various markets in which bp operates are summarized below. For information on steps that bp is taking in relation to climate change issues and for details of bp’s GHG reporting, see Sustainability – Net zero aims on page 49.
United States
In the US, bp's operations are affected by GHG regulation in a number of ways. The federal Clean Air Act (CAA), for example, regulates air emissions, permitting, fuel specifications and other aspects of our production, refining, distribution and marketing activities.
Environmental Protection Agency (EPA) regulations aimed at limiting methane emissions
from new and modified sources in the oil and natural gas sector in the US by 40-45% from 2012 levels by 2025 were the subject of an August 2020, EPA final ‘policy rule’ intended to significantly revise that regulation. This rule is the subject of litigation in the D.C.
Circuit. In addition, the Bureau of Land Management (BLM) in 2018 issued a new waste prevention rule which rescinded the prior 2017 rule regarding methane regulation on federal lands. While litigation around both rules is expected to continue, the Biden administration has taken executive action with respect to Federal regulations promulgated during the Trump administration relating to climate change, including a review of both of these rules. Other EPA GHG regulations which may affect electricity generation practices and prices and have an impact on the market for fuels used to generate electricity and on renewable
energy installations are in flux due to changes in approach between presidential administrations, as well as lawsuits challenging proposed regulations. In 2019, the EPA issued the final Affordable Clean Energy (ACE) Rule, which is intended to address GHG emissions from certain existing sources in the electricity sector, and which is intended to replace the Obama administration’s Clean Power Plan (CPP). A number of lawsuits have been filed regarding the legality of the ACE Rule and the repeal of the CPP regulations, and on 19 January 2021, the DC Circuit struck down the ACE rule in its entirety. The Biden administration may develop new regulations that more closely mirror the CPP.
The Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007 impose the Renewable Fuel Standard (RFS), requiring transportation fuel sold in the United States to contain a minimum
volume of renewable fuels. Certain state initiatives impose lower GHG emissions thresholds for transportation fuels (e.g., in California and Oregon). In 2020, EPA changed its approach to Small Refinery Exemptions based on court activity. EPA is behind schedule in setting RFS requirements for 2021 and we expect the administration to begin the process of setting 2023 and beyond volumes in 2021 as well.
The GHG mandatory reporting rule, requires operators of certain facilities and producers and importers/exporters of petroleum products to file annual GHG emissions reports with the EPA quantifying direct emissions from affected facilities, as well as volumes of petroleum products, certain natural gas liquids and GHG products and notional GHG emissions as if these products were fully combusted.
A number of states, municipalities and regional organizations have responded to current and
proposed federal changes easing environmental regulation with separate initiatives that affect our US operations. For example, the California cap and trade programme started in January 2012 and expanded to cover emissions from transportation fuels in 2015. The State of Washington has adopted a carbon cap rule although the state’s Supreme Court has modified the rule to exclude coverage of sales and distribution of petroleum fuels. We expect a number of states to advance economy-wide and transport/fuels specific regulations in 2021.
Our US businesses are subject to increased GHG and other environmental requirements and regulatory uncertainty, including that the Biden or any future US administrations could revise or revoke current or prior administration programs, as well as increased expenditures in having to comply with numerous diverse and non-uniform regulatory initiatives at the state and local level.
US
fuel markets are affected by EPA regulation of light, medium and heavy duty vehicle emissions (both fuel economy and tailpipe standards) as well as for non-road engines and vehicles and certain large GHG stationary emission sources. California also imposes Low Emission Vehicle (LEV) and Zero Emission Vehicle (ZEV) standards on vehicle manufacturers and a number of other states, as allowed by CAA authority, have adopted standards identical to California’s standards. These regulations may impact bp’s product mix and demand for particular products in those states. In August 2020, California also entered into agreements with several carmakers to meet more demanding emissions standards in California.
In 2019 the Trump administration issued the Safer Affordable Fuel-Efficient Vehicles rule rolling back the Obama administration’s fuel economy and tailpipe carbon dioxide emissions standards for passenger cars and light trucks covering
model years (MY) 2021 through 2026 by locking in the 2020 standards until 2026. It has also proposed eliminating the waiver allowing California to set its own LEV and ZEV standards and for other states to adopt those standards. Litigation challenging these regulations is ongoing although the Biden
322
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Glossary
Additional disclosures
administration is expected to restore the California waiver and commence rulemaking to reinstate the stricter fuel economy and tailpipe carbon dioxide emissions standards.
In January 2020, EPA solicited on a proposed rulemaking known as the Cleaner Trucks Initiative. The rule would, among other things, establish new emission standards for oxides of nitrogen (NOx) and other pollutants for highway heavy-duty engines and the Biden administration is expected to modify and continue this proposed rulemaking. California has also
adopted a “Heavy-Duty Low NOx Omnibus Regulation” which will require manufacturers to comply with stricter emissions standards. The rule is being phased in, with the first phase effective in 2024. bp continues to monitor these rules for implications for fuels.
European Union
•The EU and its member states have adopted various measures seeking to reduce GHG emissions and encourage renewables. A set of regulatory measures adopted by the EU include: a collective national reduction target for emissions not covered by the EU Emissions Trading System (EU ETS) Directive; binding national renewable energy targets (including targets in the transport sector) under the Renewable Energy Directive; and a legal framework to promote carbon capture and storage.
•In 2014, EU
leaders adopted a climate and energy framework setting targets for the year 2030 including at least 40% reductions in GHG emissions from 1990 levels and in December 2020 the Council agreed an increase to a 55% reductions target from 1990 levels which is pending before the European Parliament.
•In December 2019, the European Commission proposed an ambitious ‘European Green Deal’. These proposals, which require formal approval by EU Member States to be adopted and include climate neutrality and increased GHG reduction targets, tightening of the emissions caps in the EU ETS, extending the EU ETS to include the maritime sector and reducing allowances allocated to airlines, implement a carbon border tax adjustment and harmonise energy taxation across the EU Member States.
•In October 2020 the European Commission presented an EU strategy
to reduce methane emissions. The strategy sets out measures to cut methane emissions in Europe and internationally. It presents legislative and non-legislative actions in the energy, agriculture and waste sectors, which account for around 95% of methane emissions associated with human activity worldwide.
•European regulations also establish passenger car performance standards for CO2 tailpipe emissions (European Regulation (EC) No 443/2009). By 2021, the European passenger fleet emissions target for new vehicles will be 95 grams of CO2 per kilometre. This target will be achieved by manufacturing fuel efficient vehicles and vehicles using alternative, low carbon fuels such as hydrogen and electricity.
•In 2019, the European Parliament and the Council adopted Regulation (EU) 2019/631 setting CO2 emission performance
standards for new passenger cars and for new light commercial vehicles (vans) in the EU for the period after 2020. From a 2021 baseline, it requires EU fleet-wide reductions of 15% by 2025 and 37.5% by 2030 for passenger cars, and 15% by 2025 and 31% by 2030 for new light commercial vehicles.
•The EU Fuel Quality Directive affects our production and marketing of transport fuels including mandating reductions in the life cycle GHG emissions per unit of energy and tighter environmental fuel quality standards for petrol and diesel.
•Germany is expected to launch a national emissions trading system in 2021 for transport and heating fuels. Impacted fuel suppliers in Germany will pay a fixed price for emissions certificates of EUR 25 per tonne CO2 in 2021 rising to EUR 55 per tonne by 2025. In 2026, emissions certificates will be auctioned
but with prices limited between EUR 55 and EUR 65 per tonne CO2 emitted. A review of the system is expected to take place in 2025 to determine the position beyond 2026.
Other
•In December 2020 the UK Government announced a targeted reduction in the UK’s GHG emissions of at least 68% by 2030, compared to 1990 levels. The UK also announced an emissions trading system from 1
January 2021 onwards which would include the same installations in the UK that were previously subject to the EU ETS.
•China is operating emission trading pilot programmes in five cities and three provinces. One of bp's subsidiaries«
and one of bp’s joint venture« companies in China are participating in these schemes. China launched its national emissions trading market (National ETS), initially covering the power sector only, politically in 2017. On 31 December 2020, China promulgated the national regulation on National ETS which became effective on 1 February 2021, when the National ETS was officially launched.
•China has also adopted more stringent vehicle tailpipe emission standards and vehicle efficiency standards to address air pollution and GHG emissions. These standards will have an impact on transportation fuel product mix and overall demand. In addition, China has also introduced a mandate for sales of new energy vehicles (NEVs) commencing in 2020. This has been accelerating NEV penetration into the light vehicle sector and impact light fuel demand.
Other
environmental regulation
In addition to GHG regulations including current and proposed fuel and product specifications and emission controls (including control of vehicle emissions) referred to above, climate change programmes and regulation of unconventional oil and gas extraction under a number of environmental laws may have a significant effect on the production, sale and profitability of many of bp’s products.
Environmental laws also require bp to remediate and restore areas affected by the release of hazardous substances or hydrocarbons associated with our operations or properties. These laws may apply to sites that bp currently owns or operates, sites that it previously owned or operated, or sites used for the disposal of its and other parties’ waste. See Financial Statements – Note 23 for information on provisions for environmental restoration and remediation.
A
number of pending or anticipated governmental proceedings against certain bp group companies under environmental laws could result in monetary or other sanctions. Group companies are also subject to environmental claims for personal injury and property damage alleging the release of, or exposure to, hazardous substances. The costs associated with future environmental remediation obligations, governmental proceedings and claims could be significant and may be material to the results of operations in the period in which they are recognized. We cannot accurately predict the effects of future developments, such as stricter environmental laws and regulations or enforcement policies, or future events at our facilities, on the group, and there can be no assurance that material liabilities and costs will not be incurred in the future. For a discussion of the group’s environmental expenditure, see page 321 and for a discussion of legal proceedings, see page 226.
Significant
legislation and regulation in the US and the EU affecting our businesses and profitability, in addition to those referred to above, include the following:
United States
•The Clean Water Act regulates wastewater and other effluent discharges from bp’s facilities, and bp is required to obtain discharge permits, install control equipment and implement operational controls and preventative measures.
•The Resource Conservation and Recovery Act regulates the generation, storage, transportation and disposal of wastes associated with our operations and can require corrective action at locations where such wastes have been disposed of or released. bp has incurred, or is likely to incur, liability under RCRA or similar state laws in connection with sites bp operates or previously
operated.
•The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) can, in certain circumstances, impose the entire cost of investigation and remediation on a party who owned or operated a site contaminated with a hazardous substance, or who arranged for disposal of a hazardous substance at a site. bp has incurred, or is likely to incur, liability under CERCLA or similar state laws, including costs attributed to insolvent or unidentified parties. bp is also subject to claims for remediation costs and natural resource damages under CERCLA and other federal and state laws.
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bp Annual Report and Form 20-F 2020
323
•The Emergency Planning and Community Right-to-Know Act requires reporting on the storage, use and releases of certain quantities of listed hazardous substances to designated government agencies.
•The Toxic Substances Control Act (TSCA) regulates bp’s manufacture, import, export, sale and use of chemical substances and products. In addition, EPA has revised processes and procedures for prioritisation of existing chemicals for risk evaluation,
assessment and management. Agency actions and announcements are monitored regularly to identify developments with potential impacts on chemical substances important to bp products and operations. Thus far, bp has identified two substances for specific ongoing monitoring of developments and impacts.
•The Occupational Safety and Health Act imposes workplace safety and health requirements on bp operations along with significant process safety management obligations, requiring continuous evaluation and improvement of operational practices to enhance safety and reduce workplace emissions at gas processing, refining and other regulated facilities.
•The Oil Pollution Act 1990 (OPA) imposes operational requirements, liability standards and other obligations governing the transportation of petroleum products in US waters. States may impose
additional obligations. Alaska and the West Coast states currently have the most demanding state requirements.
•The Outer Continental Shelf Land Act, the Mineral Leasing Act and other statutes give the Department of Interior (DOI) and the BLM authority to regulate operations and air emissions, including equipment and testing, on offshore and onshore operations on federal lands subject to DOI authority.
•The Endangered Species Act (ESA) and Marine Mammal Protection Act protect certain species’ habitats from adverse human impacts by restricting operations or development at certain times and in certain places. In 2020, the US Fish and Wildlife Service published two proposed rules impacting designations under ESA, but on 20 January 2021 the Biden administration announced a review of these proposed rules reducing
the scope of habitat protections.
European Union
•The Industrial Emissions Directive (IED) 2010 provides the framework for granting permits for major industrial sites. It lays down rules on integrated prevention and control of air, water and soil pollution arising from industrial activities. As part of the IED framework, additional emission limit values are informed by sector specific and cross-sector Best Available Technology (BAT) Conclusions. These include the BAT Conclusions for the refining sector, for large combustion plants as well as common wastewater and waste gas treatment and management systems in the chemical sector. These may require bp to further reduce its emissions, particularly its air and water emissions.
•The EU Regulation on substances that deplete
the ozone layer 2009 (ODS Regulation) requires companies to reduce the use of ozone depleting substances (ODSs) and phase out use of certain ODSs. bp continues to replace ODSs in refrigerants and/or equipment in the EU and elsewhere, in accordance with the Montreal Protocol and related legislation.
•The Medium Combustion Plants Directive 2015 (MCPD) regulates sulphur dioxide (SO2), nitrogen oxides (NOx) and particulates emissions and monitoring of carbon monoxide (CO) emissions from certain mid-size plants. It applies to new plants and by 2025 or 2030 to existing plants, depending on their size.
•The National Emission Ceilings Directive 2016 (NECD) introduces stricter emissions limits from 2020 and 2030, with new indicative national targets applying from 2025. NECD has been implemented in the UK by the National Emission Ceilings Regulations
2018. Each EU Member State was also required to produce a National Air Pollution Control Programme setting out the measures it will take to ensure compliance with the 2020 and 2030 reduction commitments.
•The EU Registration, Evaluation Authorization and Restriction of Chemicals (REACH) Regulation 2006 requires registration of chemical substances manufactured in or imported into the EU, together with the submission of relevant hazard and risk data. REACH affects our manufacturing or trading/import operations in the EU. bp maintains
compliance by checking whether imports are covered by the registrations of non-EU suppliers’ representatives, preparing and submitting registration dossiers to cover new manufactured and imported substances, and updating previously submitted registrations as required. Some substances
registered previously, including substances supplied to us by third parties for our use, are now subject to evaluation and review for potential authorization or restriction procedures, and possible banning, by the European Chemicals Agency and EU Member State authorities. In addition, bp’s facilities and operations in several EU countries continue to undergo REACH compliance inspections by the competent authority for the respective EU Member State. An amendment to the Annex of the Regulation on classification, labelling and packaging of substances and mixture (CLP Regulation) requires harmonized notification of information on hazardous materials (certain lubricant and fuel formations) to EU Member State poison centres. The uniform notification rules apply as of January 2020 for consumer products, from 2021 for professional and 2024 for industrial uses.
•The EU Offshore Safety Directive was adopted
in 2013. Its purpose is to introduce a harmonized regime aimed at reducing the potential environmental, health and safety impacts of the offshore oil and gas industry throughout EU waters. The Directive has been implemented in the UK primarily through the Offshore Installations (Offshore Safety Directive) (Safety Case etc.) Regulations 2015.
•The Water Framework Directive (WFD) published in 2000 aims to protect the quantity and quality of ground and surface waters of the EU Member States. The implementation in the EU Member States is still ongoing, planned to be finalised by 2027. A Fitness Check (comprehensive policy evaluation) of the EU Water Legislation launched in 2019 concluded that the WFD is broadly fit for purpose. Future proceedings on the determination of pollutants/priority substances as well as environmental quality standards in line with the WFD may require additional compliance efforts
and increased costs for managing freshwater withdrawals and discharges from bp’s EU operations.
United Kingdom
Following the UK’s exit from the European Union on 31 January 2020, the UK entered a transition period which ran until 31 December 2020. During the transition period, most EU law continued to apply to the UK and therefore to bp’s UK business during that period. From 1 January 2021, operative EU laws were retained in UK law by the European Union (Withdrawal) Act 2018. The vast majority of environment related statutory instruments passed by the UK Government in anticipation of Brexit have included no substantive changes to the current EU underlying regime, but rather seek to make the amendments required to allow their continued operation after the transition period. The UK Government’s Environment Bill and 25 Year Plan will be central to the UK’s environmental regime going
forward but further changes are as yet uncertain.
Other countries and regions
Regulations governing the discharge of treated water have also been developed in countries outside of the US and EU. This includes regulations in Trinidad and Angola which impacts bp’s production operations in those countries. In Trinidad, bp commissioned a new waste water treatment plant in 2020 to meet consent levels agreed with the regulators to apply water discharge rules arising from the Certificate of Environmental Clearance (CEC) Regulations 2001 and associated Water Pollution Rules 2007. In Angola, bp has upgraded produced water treatment systems to meet revised oil in water limits for produced water discharge under Executive Decree ED 97-14.
The Abidjan Convention, along with the Additional Protocol published in 2012, sets environmental quality standards
for the discharge of chemicals to the marine environment. The convention and associated protocols has been ratified by 19 African nations including Senegal and Mauritania. bp is currently constructing the offshore facilities to include produced water management systems to meet the environmental quality standards for our future gas operations in Mauritania and Senegal.
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Additional disclosures
Environmental maritime regulations
bp’s shipping operations are subject to extensive national and international regulations governing operations, training, pollution prevention, liability, and insurance. These include:
•Liability and spill prevention and planning requirements governing, among others, tankers, barges, and offshore facilities are imposed by OPA in US waters. OPA also mandates a levy on imported and domestically
produced oil to fund oil spill responses. Some states, including Alaska, Washington, Oregon and California, impose additional liability for oil spills. Outside US territorial waters, bp shipping tankers are subject to international pollution prevention, liability, spill response and preparedness regulations developed through the UN’s International Maritime Organization (IMO), including the International Convention on Civil Liability for Oil Pollution Damage, the International Convention for the Prevention of Pollution from Ships (MARPOL), the International Convention on Oil Pollution, Preparedness, Response and Co-operation, and the International Convention on Civil Liability for Bunker Oil Pollution Damage. In April 2010, the Hazardous and Noxious Substance (HNS) Protocol 2010 was adopted to address issues that have inhibited ratification of the International Convention on Liability and Compensation for Damage in Connection with the Carriage of Hazardous and Noxious
Substances by Sea 1996. As at 31 December 2020, the HNS Convention had not entered into force.
•A global sulphur cap of 0.5% applies to marine fuel under MARPOL. In order to comply, ships either need to consume low sulphur marine fuels, operate on alternative low sulphur fuels such as LNG or implement approved abatement technology to enable them to meet the low sulphur emissions requirements while continuing to use higher sulphur fuel. This global cap does not alter the lower limits that apply in the sulphur oxides Emissions Control Areas established by the IMO.
•The Convention for the Protection of the Marine Environment of the North-East Atlantic (OSPAR), aims to protect the marine environment of the North-East Atlantic. The OSPAR 2012 Recommendation and Guideline for the implementation of a risk-based approach to the management
of produced water discharges from offshore installations in the North Sea supports a key goal of working towards eliminating harmful discharges. In 2020 the International Association of Oil and Gas Producers issued a report “Oil And Gas Risk Based Assessment of Offshore Produced Water Discharges” which presents industry good practice and aims to broaden the understanding and acceptance of Risk Based Assessment (RBA) techniques internationally and improve consistency in the application of assumptions, levels of conservatism, and selection of risk endpoints.
To meet its financial responsibility requirements, bp Shipping maintains marine oil pollution liability insurance in respect of its operated ships to a maximum limit of $1 billion for each occurrence through mutual insurance associations (P&I Clubs), although there can be no assurance that a spill would necessarily be adequately covered by insurance or that liabilities
would not exceed insurance recoveries.
International trade sanctions
During the period covered by this report, non-US subsidiaries«, or other non-US entities of BP, conducted limited activities in, or with persons from, certain countries identified by the US Department of State as State Sponsors of Terrorism or otherwise subject to US and EU sanctions (Sanctioned Countries). Sanctions restrictions continue to be insignificant to the group’s financial condition and results of operations. BP monitors its activities with Sanctioned Countries, persons from Sanctioned Countries and individuals and companies subject to US, EU and
(following the end of the Brexit transition period) UK sanctions and seeks to comply with applicable sanctions laws and regulations.
BP has a 28.83% interest in and operates the Shah Deniz field in Azerbaijan (Shah Deniz), has a 28.83% interest in and performs some operations for a related gas pipeline entity, South Caucasus Pipeline Company Limited (SCPC), and has a 23% non-operating interest in a related gas marketing entity, Azerbaijan Gas Supply Company Limited (AGSC). Naftiran Intertrade Co. Limited and NICO SPV Limited (collectively, NICO) have a 10% non-operating interest in each of Shah
Deniz and SCPC and an 8% non-operating interest in AGSC. Shah Deniz, SCPC and AGSC continue in operation as they were excluded from the application of US sanctions and fall within the exception for certain natural gas projects under Section 603
of the Iran Threat Reduction and Syria Human Rights Act of 2012 (ITRA).
On 3 December 2018 BP entered into an agreement with, among others, SOCAR and NICO pursuant to which SOCAR pays to BP Exploration (Shah Deniz) Limited (BPXSD), as the Shah Deniz operator, compensation for NICO’s waiver of its right to lift its share of Shah Deniz condensate. Such amounts are used to cover cash calls to NICO in respect of operating costs due from NICO to BPXSD. On 26 October 2020, OFAC issued an amended licence in relation to these arrangements.
Following the imposition in 2011 of further US and EU sanctions against Syria, BP terminated all sales of crude oil and petroleum products into Syria, though BP continues to supply aviation fuel to non-governmental Syrian resellers outside of Syria.
BP has a joint arrangement in Cuba which imports, manufactures,
markets and sells lubricants.
During 2014, the US and the EU imposed sanctions on certain sectors of the Russian economy (energy, finance and defence/military) and on certain individuals and entities, including Rosneft. These sectoral sanctions include restrictions on the provision of financial assistance, technical assistance, and services in relation to exploration and production activity in deep water, shale, and offshore Arctic.
Additional US sanctions have been imposed since 2014, broadening the scope of US sanctions on Russia-related activity to include certain international deep water, shale, and offshore Arctic projects as well as the provision of goods and services for Russian energy export pipelines. As of 1 January 2021, as a result of the UK’s exit from the EU, the UK has also imposed Russian-related sanctions, which are broadly similar to existing EU sanctions.
We
are not aware of any material adverse effect on our current income and investment in Russia or elsewhere as a consequence of these sanctions.
BP maintains bank accounts and has registered and paid required fees to maintain registrations of patents and trademarks in certain Sanctioned Countries.
BP has equity interests in non-operated joint arrangements« with air fuel sellers, resellers, and fuel delivery services around the world.
From time to time, the joint arrangement operator or other partners may sell or deliver fuel to airlines from Sanctioned Countries or flights to Sanctioned Countries, without BP's involvement.
BP has no control over the activities non-controlled associates« may undertake in Sanctioned Countries or with persons from Sanctioned Countries.
Disclosure pursuant to ITRA Section 219
To our knowledge, none of BP’s activities, transactions or dealings are required to be disclosed pursuant to ITRA Section 219, with the following possible exceptions.
On 17 July 2018, BP Iran Limited terminated its lease of an office in Tehran. The office had been used for administrative activities. In 2020, taxes with an aggregate US dollar equivalent value of approximately $20,000 were paid from a BP trust account held with Tadvin Co. to Iranian public entities. No gross revenues or net profits were attributable to these activities.
BP has a 29.3% interest in Middle East Lubricants Company LLC (Melubco), which is established and manufactures lubricants
in the United Arab Emirates. In May 2020, Melubco successfully appealed an Iranian court judgment obtained against it in absentia for non-payment of shipping fees. The applicant, an Iranian shipping company, had confused Melubco with an unrelated, but similarly named, Iranian entity. In order to do so, Melubco paid court filing fees equivalent to approximately $3,000 to the Tehran Judicial Services Office. Melubco does not, and has never, done business in Iran.
On 4 April 2016 the district court approved the Consent Decree among BP Exploration & Production Inc., BP Corporation North America Inc., BP p.l.c., the United States and the states of Alabama, Florida, Louisiana, Mississippi and Texas (the Gulf states) which fully and finally resolved any and all natural resource damages (NRD) claims of the United States, the Gulf states, and their
respective natural resource trustees and all Clean Water Act (CWA) penalty claims, and certain other claims of the United States and the Gulf states.
Concurrently, the definitive Settlement Agreement that bp entered into with the Gulf states (Settlement Agreement) with respect to State claims for economic, property and other losses became effective.
bp has filed the Consent Decree and the Settlement Agreement as exhibits to its Annual Report on Form 20-F 2020 filed with the SEC. For further details of the Consent Decree and the Settlement Agreement, see Legal proceedings in bp Annual Report and Form 20-F 2015.
Property, plant and equipment
bp
has freehold and leasehold interests in real estate and other tangible assets in numerous countries, but no individual property is significant to the group as a whole. For more on the significant subsidiaries« of the group at 31 December 2020 and the group percentage of ordinary share capital see Financial statements – Note 37. For information on significant joint ventures« and associates« of the group see Financial statements – Notes 16 and 17.
Related-party transactions
Transactions between the group and its significant joint ventures
and associates are summarized in Financial statements – Note 16 and Note 17. In the ordinary course of its business, the group enters into transactions with various organizations with which some of its directors or executive officers are associated. Except as described in this report, the group did not have any material transactions or transactions of an unusual nature with, and did not make loans to, related parties in the period commencing 1 January 2020 to 2 March 2021.
Corporate governance practices
In the US, bp ADSs are listed on the New York Stock Exchange (NYSE). The significant differences between bp’s corporate governance practices as a UK company and those required by NYSE listing standards for US companies are listed as follows:
Independence
In
2020 bp continued to apply its board governance principles. These reflect the UK Corporate Governance Code approach to corporate governance. As such, the way in which bp makes determinations of directors’ independence differs from the NYSE rules. As set out on page 88, from 1 January 2021 bp has adopted terms of reference for the board and each of its committees.
bp’s board governance principles require that all non-executive directors be determined by the board to be ‘independent in character and judgement and free from any business or other relationship which could materially interfere with the exercise of their judgement’. The bp board has determined that, in its judgement, all of the non-executive directors are independent. In doing so, however, the board did not explicitly take into consideration the independence requirements outlined in the NYSE’s listing standards.
Committees
bp
has a number of board committees that are broadly comparable in purpose and composition to those required by NYSE rules for domestic US companies. For instance, bp has a remuneration (rather than a compensation) committee. bp also has an audit committee, which NYSE rules require for both US companies and foreign private issuers. These committees are composed solely of non-executive directors whom the board has determined to be independent, in the manner described above.
The bp board governance principles prescribe the composition, main tasks and requirements of each of the committees (see the board committee
reports on pages 92-102 and 105). Therefore, during 2020 bp did not have separate charters for each committee. As from the start of 2021 each of the board committees has adopted its own terms of reference which set out their respective
roles and responsibilities.
Under US securities law and the listing standards of the NYSE, bp is required to have an audit committee that satisfies the requirements of Rule 10A-3 under the Exchange Act and Section 303A.06 of the NYSE Listed Company Manual. bp’s audit committee complies with these requirements. The bp audit committee does not have direct responsibility for the appointment, reappointment or removal of the independent auditors. Instead, it follows the UK Companies Act 2006 and the UK Corporate Governance code 2018 by making recommendations to the board on these matters for it to put forward for shareholder approval at the AGM.
One of the NYSE’s additional requirements for the audit committee states that at least one member of the audit committee is to have ‘accounting or related financial management expertise’. The board determined that Brendan Nelson possesses such
expertise and also possesses the financial and audit committee experiences set forth in both the UK Corporate Governance Code and SEC rules (see Audit committee report on page 94). Mr Nelson is the audit committee financial expert as defined in Item 16A of Form 20-F.
Shareholder approval of equity compensation plans
The NYSE rules for US companies require that shareholders must be given the opportunity to vote on all equity-compensation plans and material revisions to those plans. bp complies with UK requirements that are similar to the NYSE rules. The board, however, does not explicitly take into consideration the NYSE’s detailed definition of what are considered ‘material revisions’.
Code of ethics
The NYSE rules require that US companies adopt and disclose a code of business conduct and ethics
for directors, officers and employees. bp has adopted a code of conduct, which applies to all employees and members of the board, and has board governance principles that address the conduct of directors. In addition bp has adopted a code of ethics for senior financial officers as required by the SEC. bp considers that these codes and policies address the matters specified in the NYSE rules for US companies.
Code of ethics
The company has adopted a code of ethics for its group chief executive, chief financial officer, group controller, group head of audit and chief accounting officer as required by the provisions of Section 406 of the Sarbanes-Oxley Act of 2002 and the rules issued
by the SEC. There have been no waivers from the code of ethics relating to any officers.
bp also has a code of conduct, which is applicable to all employees, officers and members of the board. This was updated (and published) in July 2014.
Controls and procedures
Evaluation of disclosure controls and procedures
The company maintains ‘disclosure controls and procedures’, as such term is defined in Exchange Act Rule 13a-15(e), that are designed to ensure that information required to be disclosed in reports the company
files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms, and that such information is accumulated and communicated to management, including the company’s group chief executive and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure.
In designing and evaluating our disclosure controls and procedures, our management, including the group chief executive and chief financial officer, recognize that any controls and procedures, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the disclosure controls and procedures are met. Because of the inherent limitations in all control systems, no evaluation of controls can provide
absolute assurance that all control issues and instances of fraud within the company, if any, have been
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Additional
disclosures
detected. Further, in the design and evaluation of our disclosure controls and procedures our management necessarily was required to apply its judgement in evaluating the costs and benefits of possible control and procedure design options. Also, we have investments in unconsolidated entities. As we do not control these entities, our disclosure controls and procedures with respect to such entities are necessarily substantially more limited than those we maintain with respect to our consolidated subsidiaries«. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. The
company’s disclosure controls and procedures have been designed to meet, and management believes that they meet, reasonable assurance standards.
The company’s management, with the participation of the company’s group chief executive and chief financial officer, has evaluated the effectiveness of the company’s disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(b) as of the end of the period covered by this annual report. Based on that evaluation, the group chief executive and chief financial officer have concluded that the company’s disclosure controls and procedures
were effective at a reasonable assurance level.
Management’s report on internal control over financial reporting
Management of bp is responsible for establishing and maintaining adequate internal control over financial reporting. bp’s internal control over financial reporting is a process designed under the supervision of the principal executive and financial officers to provide reasonable assurance regarding the reliability of financial reporting and the preparation of bp’s financial statements for external reporting purposes in accordance with IFRS.
As of the end of the 2020 fiscal year, management conducted an assessment of the effectiveness of internal control over financial reporting in accordance with the criteria in the UK Financial Reporting Council’s Guidance on Risk Management, Internal Control and Related Financial and Business
Reporting relating to internal control over financial reporting. Based on this assessment, management has determined that bp’s internal control over financial reporting as of 31 December 2020 was effective.
The company’s internal control over financial reporting includes policies and procedures that pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; provide reasonable assurances that transactions are recorded as necessary to permit preparation of financial statements in accordance with IFRS and that receipts and expenditures are being made only in accordance with authorizations of management and the directors of bp; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of bp’s assets that
could have a material effect on our financial statements. bp’s internal control over financial reporting as of 31 December 2020 has been audited by Deloitte LLP, an independent registered public accounting firm, as stated in their report appearing on page 154 of bp Annual Report and Form 20-F 2020.
Changes in internal control over financial reporting
There were no changes in the group’s internal control over financial reporting that occurred during the period covered by the Form 20-F that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
Principal
accountant's fees and services
The audit committee has established policies and procedures for the engagement of the independent registered public accounting firm, Deloitte LLP, to render audit and certain assurance services. The policies provide for pre-approval by the audit committee of specifically defined audit, audit-related, non-audit and other services that are not prohibited by regulatory or other professional requirements. Deloitte is engaged for these services when its expertise and experience of bp are important. Most of this work is of an audit nature. The committee regularly reviews
the policy, including in 2020, when it was updated to reflect changes resulting from the FRC Ethical Standard (December 2019).
Under
the policy, pre-approval is given for specific services within the following categories: advice on accounting, auditing and financial reporting matters; internal accounting and risk management control reviews (excluding any services relating to information systems design and implementation); non-statutory audit; project assurance and advice on business and accounting process improvement (excluding any services relating to information systems design and implementation relating to bp’s financial statements or accounting records); provision of, or access to, Deloitte publications, workshops, seminars and other training materials; provision of reports from data gathered on non-financial policies and information; provision of the independent third party audit in accordance with US Generally Accepted Government Auditing Standards, over the company’s Conflict Minerals Report – where such a
report is required under the SEC rule ‘Conflict Minerals’, issued in accordance with Section 1502 of the Dodd Frank Act; and assistance with understanding non-financial regulatory requirements. bp operates a two-tier system for audit and non-audit services. For audit related services, the audit committee has a pre-approved aggregate level, within which specific work may be approved by management. Non-audit services are pre-approved for management to authorize per individual engagement, but above a defined level must be approved by the chairman of the audit committee or the full committee. In response to the revised regulatory guidelines of the UK Financial Reporting Council, the audit committee reviewed and updated its policies with effect from 1 January 2017 and in 2018 further updated its policies to clarify the engagement of the incoming auditor, Deloitte, and the outgoing auditor Ernst & Young to ensure independence. The defined maximum level for pre-approval
has been reduced in line with FRC guidance on ‘non-trivial’ engagements. The audit committee has delegated to the chairman of the audit committee authority to approve permitted services provided that the chairman reports any decisions to the committee at its next scheduled meeting. Any proposed service not included in the approved service list must be approved in advance by the audit committee chairman and reported to the committee, or approved by the full audit committee in advance of commencement of the engagement.
The audit committee evaluates the performance of the auditor each year. The audit fees payable to Deloitte are reviewed by the committee in the context of other global companies for cost effectiveness. The committee keeps under review the scope and results of audit work and the independence and objectivity of the auditor. External regulation and bp policy requires the auditor to rotate its lead audit partner every
five years. See Financial statements – Note 36 and Audit committee report on page 94 for details of fees for services provided by the auditor.
Directors’ report information
This section of bp Annual Report and Form 20-F 2020forms part of, and includes certain disclosures which are required by law to be included in, the Directors’ report.
Indemnity provisions
In accordance with BP’s Articles of Association, on appointment each director is granted an indemnity from the
company in respect of liabilities incurred as a result of their office, to the extent permitted by law. These indemnities were in force throughout the financial year and at the date of this report. In respect of those liabilities for which directors may not be indemnified, the company maintained a directors’ and officers’ liability insurance policy throughout 2020. During the year, a review of the terms and scope of the policy was undertaken as part of the annual renewal. Although their defence costs may be met, neither the company’s indemnity nor insurance provides cover in the event that the director is proved to have acted fraudulently or dishonestly. Certain subsidiaries«
are trustees of the group’s pension schemes. Each director of these subsidiaries is granted an indemnity from the company in respect of liabilities incurred as a result of such a subsidiary’s activities as a trustee of the pension scheme, to the extent permitted by law. These indemnities were in force throughout the financial year and at the date of this report.
«See Glossary
bp Annual Report and Form 20-F 2020
327
Financial risk management objectives and policies
The disclosures in relation to financial risk management objectives and policies, including the policy for hedging, are included in How we manage risk on page 64, Liquidity and capital resources on page 306 and Financial statements – Notes 29 and 30.
Exposure to price risk, credit risk, liquidity risk and cash flow risk
The disclosures in relation to
exposure to price risk, credit risk, liquidity risk and cash flow risk are included in Financial statements – Note 29.
Important events since the end of the financial year
Disclosures of the particulars of the important events affecting bp which have occurred since the end of the financial year are included in the Strategic report as well as in other places in the Directors’ report.
Likely future developments in the business
An indication of the likely future developments in the business of the company is included in the Strategic report.
Research and development
Indications of our activities in the field of research and
development are provided throughout the Strategic report and the Directors’ report including examples on pages 16 (developing next-gen mobility solutions), 17 (driving digital innovation including through bp ventures and Launchpad), 19 (partnering to develop a project to produce hydrogen from water), 36 (innovation and engineering) and 63 (collaborating with universities and academic research). See also page 183 for our expenditure on research and development.
Branches
As a global group our interests and activities are held or operated through subsidiaries, branches, joint arrangements« or associates« established in – and subject to the laws and regulations of – many different jurisdictions.
Employees
Disclosures
in respect of how the directors have engaged with employees and had regard to their interests are included in How the board has engaged with shareholders, the workforce and other stakeholders on page 86 and section 172 statement on pages 63, 82 and 83.
The disclosures concerning policies in relation to the employment of disabled persons and employee involvement are included in Sustainability – People and society on page 57.
Employee share schemes
Certain shares held as a result of participation in some employee share plans carry voting rights. Voting rights in respect of such shares are exercisable via a nominee. Dividend waivers are in place in respect of unallocated shares held in employee share plan trusts.
Suppliers, customers and others
Disclosures
in respect of how the directors have engaged with suppliers, customers and others in business relationships with the company are included in How the board has engaged with shareholders, the workforce and other stakeholders on page 86 and section 172 statement on pages 63, 82 and 83.
Change of control provisions
On 5 October 2015, the United States lodged with the district court in MDL 2179 a proposed Consent Decree between the United States, the Gulf states, BP Exploration & Production Inc., BP Corporation North America Inc. and BP p.l.c., to fully and finally resolve any and all natural resource damages claims of the United States, the Gulf states and their respective natural resource trustees and all Clean Water Act penalty claims, and certain other claims of the United States and the Gulf
states. Concurrently, bp entered into a definitive Settlement Agreement with the five Gulf states (Settlement Agreement) with respect to state claims for economic, property and other losses. On 4 April 2016, the district court approved the Consent Decree, at which time the Consent Decree and Settlement Agreement became effective. The federal government and the Gulf states may jointly elect to accelerate the payments under the Consent Decree in the event of a change of control or insolvency of BP p.l.c., and the Gulf states individually have similar acceleration rights under the Settlement Agreement. For further details of the Consent Decree and the Settlement Agreement, see Legal proceedings in BP Annual Report and Form 20-F 2015.
Greenhouse gas emissions, energy consumption and energy efficiency
Disclosures in relation to greenhouse
gas emissions, energy consumption and energy efficiency are included in Sustainability – on page 50.
Disclosures required under Listing Rule 9.8.4R
The information required to be disclosed by Listing Rule 9.8.4R can be located as set out below:
Information required
Page
(1) Amount of interest capitalized
183
(2)
– (4)
Not applicable
(5), (6) Waiver of director emoluments
121
(7) – (11)
Not applicable
(12), (13) Dividend waivers
328
(14)
Not applicable
328
bp
Annual Report and Form 20-F 2020
«See Glossary
Additional disclosures
Cautionary statement
In order to utilize the ‘safe harbor’ provisions of the United States Private Securities Litigation Reform Act of 1995 (the ‘PSLRA’) and the general doctrine of cautionary statements, bp is providing the
following cautionary statement.
This document contains certain forecasts, projections and forward-looking statements - that is, statements related to future, not past, events and ircumstances - with respect to the financial condition, results of operations and businesses of bp and certain of the plans and objectives of bp with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘anticipates’, ‘plans’, ‘we see’ or similar expressions. In particular, among other statements, (i) certain statements in the Chairman’s letter (pages 4-5), the Group chief executive’s letter (pages 6-7), the Strategic report (inside cover and pages 1-70), Additional disclosures (pages 301-330) and Shareholder information (pages 331-340), including but not limited to statements
under the headings ‘Our Energy Outlook’, ‘Reinventing bp – our business model’, ‘Reinventing bp – our strategic focus areas’, ‘Reinventing bp – our financial frame’, ‘2021 guidance’ and ‘Reinventing bp – in line with the Paris goals’ and including but not limited to statements regarding: plans and expectations relating to operating cash flow, capital expenditure (including total capital expenditure, organic capital expenditure and inorganic capital expenditure), maintaining a strong financial frame, deleveraging bp’s balance sheet, working capital and operating cash flows, liquidity, capital discipline, future sustainable free cash flow and shareholder distributions, allocation of capital to bp’s energy transition strategy, amount or timing of payments related to divestment proceeds, net debt, gearing and future dividend payments and share buybacks; bp’s ambition to be a net zero company by 2050 or sooner, including its aims regarding Scope 1, Scope 2 and Scope 3 emissions,
its expectations for the energy transition and the carbon content of its oil and gas production, while operating a high-quality base business; bp’s plan to amplify value by focusing on integrating energy systems, partnering with countries, cities and industries, and driving digital innovation; expectations regarding medium and long-term oil prices, the consistency of pricing assumptions with scenarios that are consistent with the Paris goals and bp’s resilience to Paris-consistent pathways; expectations regarding world energy demand, including the growth in relative demand for renewables, oil and gas, and the proportional growth of renewables; expectations regarding bp’s short, medium- and long-term targets and aims for emissions and carbon intensity of bp’s production and marketed products, and statements regarding the resilience of bp’s strategy and portfolio across multiple climate scenarios and the uncertainties in the energy transition; plans and expectations regarding
bp’s level of investment in energy sources and technologies other than oil and gas resources and reserves, including plans to increase investment in low carbon from around $750 million in 2020 to $3-4 billion by 2025 and to around $5 billion a year in 2030, with transition capital spend to be as much as 50% of capex in 2030; plans and expectations to significantly increase bp’s investment in low carbon activities in this decade, while also operating a high-quality base business; plans and expectations regarding bp’s five aims to get bp to net zero, including the aim to be net zero across its entire operations on an absolute basis by 2050 or sooner, the aim to be net zero on an absolute basis across the carbon in its upstream oil and gas production by 2050 or sooner, the aim to cut the carbon intensity of products sold by 50% by 2050 or sooner, the aim to install methane measurement at all existing major oil and gas processing sites by 2023, publish the data, and then
drive a 50% reduction in methane intensity of operations, and the aim to increase the proportion of investment bp makes into its non-oil and gas businesses; plans and expectations regarding bp’s five aims to get the world to net zero carbon emissions, including the aim to more actively advocate for policies that support net zero, including carbon pricing, the aim to incentivize bp’s global workforce to deliver on these aims and mobilize them to become advocates for net zero, the aim to set new expectations for relationships with trade associations around the globe, the aim to be recognized as an industry leader for the transparency of its reporting and the aim to launch a new team to create integrated clean energy and mobility solutions; expectations with respect to oil and gas supply and demand and prices; expectations with respect to the world energy mix, production, consumption and emissions; plans and
expectations
with respect to low carbon spend in 2021; expectations with respect to transition capital, and the percentage of capital expenditure that will be low-carbon; expectations that the aftermath of the pandemic will accelerate the pace of transition to a lower carbon economy and energy system; expectations that the Empire Wind project in New York state will have 2GW generating capacity once operational and Beacon Wind will have 2.4GW generating capacity once operational; expectations regarding future legislative or regulatory action related to greenhouse gases, including emissions disclosure, emissions trading, and fuel-specific regulations, and their impact on bp; expectations regarding pensions and other post-retirement benefits, including contributions; expectations regarding payments under contractual obligations and sales commitments; expectations that around 10,000 employees will leave bp by early 2022; plans and expectations regarding bp’s workforce, including bp’s
targets regarding diversity, inclusion and equality; expectations regarding bp’s ability to prevent violations of its code of conduct, including its anti-bribery and corruption policies and procedures; plans and expectations regarding the new leadership structure and governance framework, including areas of focus and effectiveness; plans for incentivising bp’s global workforce; policies and goals related to risk management plans; plans and expectations regarding control deficiencies; expectations regarding bp’s ability to prevent, respond to and recover from cyberattacks or hostile actions; plans and projections regarding oil and gas reserves, including the turnover time of proved undeveloped reserves to proved developed reserves and volume of turnover; expectations regarding the costs of environmental restoration, remediation and abatement programmes; plans and expectations regarding bp’s portfolio, including to maintain a focused portfolio, to manage the portfolio
through disciplined investment to support growing returns and to focus on highest-quality barrels; expectations that by 2030 bp’s hydrocarbon production will be around 40% lower relative to 2019 due to active management and high-grading of the portfolio, including divestment of non-core assets; plans and expectations that bp will not undertake exploration activity in new countries; expectations regarding contingent liabilities and their impact on bp; expectations regarding the future value of assets; expectations with respect to reserves bookings from new discoveries; plans and expectations with regard to the supply and trading function, the fuels and the lubricants businesses; plans and expectations with regard to new technologies, including their efficiency and impact on production; plans and expectations regarding sales commitments of bp and its equity-accounted entities; expectations regarding underlying production and capital investment; expectations with respect
to ROACE and earnings before interest, tax, depreciation and amortisation; plans and expectations regarding investment, development, and production levels and the timing thereof with respect to projects and partnerships in Angola, Australia, Azerbaijan, Brazil, Egypt, the Gambia, India, Indonesia, Mexico, Russia, São Tomé and Príncipe, Turkey, Oman, the UK North Sea, the Gulf of Mexico, and the continental United States; expectations regarding refining margins; plans to undertake joint exploration and development with Rosneft and plans and expectations for the Strategic Collaboration Agreement signed between Rosneft and bp; expectations regarding future government action, regulations and policy, their impact on bp’s business and plans regarding compliance with such regulations; expectations regarding legal and trial proceedings, court decisions, potential investigations and civil actions by regulators, government entities and/ or other entities or parties, and the timing
and potential impact of such proceedings and bp’s intentions in respect thereof; plans and expectations regarding relationships with governments, customers, partners, suppliers, communities and key stakeholders; plans to produce 900,000boe/d from new projects by 2021 and expectations regarding operating cash margins of this production; plans and expectations for bp’s Jio-bp joint venture with Reliance, including the expectation for 5,500 Jio-bp retail sites by 2025; plans and expectations to deliver 2021 financial targets; plans to increase investment in low carbon to $3-4 billion by 2025 and to around $5 billion a year in 2030; expectations related to delivery and execution of Atlantis Phase 3 in the US Gulf of Mexico; expectations regarding customer touchpoints, number of strategic convenience sites, number of retail sites in growth markets, Castrol sales and other operating revenues, number of electric vehicle charge points, margin share from convenience and electrification,
unit production costs, Upstream production, Upstream plant reliability, refining throughout, refining availability, developed renewables to final investment decision, bioenergy production, LNG portfolio, and traded electricity;
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bp Annual Report and Form 20-F 2020
329
expectations
regarding oil prices, including for long-term prices to be affected by the enduring impact of the COVID-19 pandemic, the decisions of OPEC+, confidence in efforts to manage the rollout of vaccination and further virus control measures; expectations regarding Upstream reported production excluding Rosneft , total capital expenditure, depreciation, depletion and amortisation charges, Gulf of Mexico oil spill payments (post-tax), the Other business and corporate annual charge and underlying quarterly charge, and the effective tax rate and the underlying effective tax rate; plans and expectations regarding the effectiveness of the group’s foreign currency exchange risk management; expectations regarding bp’s partnership with Equinor for offshore wind in the US, including bp’s expectation of pursuing further opportunities for offshore wind in the US, and regarding bp’s partnership with Ørsted on an industrial-scale project to produce hydrogen from water, powered by wind;
expectations regarding the US gas market in 2021 as supply declines and demand for LNG exports recovers and that the current tightness on global LNG markets and higher US gas prices will lift other regional gas prices; expectations for limited growth in oil supply from non-OPEC+ countries coupled with active market management from OPEC+ leading to normalization of the currently high inventory levels, with prices subject to the decisions of OPEC+; expectations that US gas markets are likely to benefit from lower production and a recovery in international LNG demand driven by demand in Asia; expectations that demand for refined products will remain strong over the remaining useful life of existing assets; expectations that the majority of bp’s Upstream oil and gas properties will start decommissioning within the next two decades; expectations that the majority of bp’s reserves and resources that support the carrying value of the group’s existing oil and gas properties
are expected to be produced over the next 10 years; expectations that reported production will be lower due to the impact of the ongoing divestment programme; expectations regarding level and volatility of other businesses and corporate charges for 2021; plans and expectations regarding bp’s in-scope projects’ impact on biodiversity; expectation’s regarding bp’s impact on air emissions and water use and management; expectations regarding fulfillment of existing delivery commitments for oil and gas; expectations regarding Gulf of Mexico oil spill payments; expectations that first oil from the Thunder Horse South Expansion will be reached in the third quarter of 2021 and that first oil for the Mad Dog 2 project will be reached in the second quarter of 2022; expectations that the Cassia Compression project will start up in 2022; expectations that first production from the Total-operated Zinia 2 deep offshore development project will occur in 2021; expectation that first
production from the Platina project will occur in 2021; expectation for start-up of the West Nile Delta Raven project in the first quarter of 2021; expectations that the Tangguh expansion project will start-up in 2022; and plans and expectations regarding bp Ventures and Launchpad; and (ii) certain statements in Corporate governance (pages 71-102) and the Directors’ remuneration report (pages 103-126) with regard to: the anticipated future composition of the board of directors and the effects thereof; the board’s goals and areas of focus, including changes to KPIs and those goals stemming from the board’s annual evaluation; plans and expectations regarding directors’ share ownership and remuneration; plans regarding the governance and remuneration processes; and goals, activities and areas of focus of board committees, are all forward looking in nature. By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on
circumstances that will or may occur in the future and are outside the control of bp. Actual results may differ materially from those expressed in such statements, depending on a variety of factors, including: the specific factors identified in the discussions accompanying such forward looking statements; the effects of the COVID-19 pandemic and uncertainties about its impact and duration; the receipt of relevant third party and/or regulatory approvals; the timing and level of maintenance and/or turnaround activity; the timing and volume of refinery additions and outages; the timing of bringing new projects onstream; the timing, quantum and nature of certain acquisitions and divestments; future levels of industry product supply, demand and pricing, including supply growth in North America; OPEC+ quota restrictions; production-sharing agreements effects; operational and safety problems; potential lapses in product quality; economic and financial market conditions generally
or in various countries and regions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations and policies, including related to climate change; changes in social attitudes and customer
preferences; regulatory or legal actions including the types of enforcement action pursued and the nature of remedies sought or imposed; the actions of prosecutors, regulatory authorities and courts; delays in the processes for resolving claims; amounts ultimately determined to be payable and the timing of payments relating to the Gulf of Mexico oil spill; exchange rate fluctuations; development and use of new technology; recruitment and retention of a skilled workforce; the success or otherwise of partnering; the actions of competitors, trading partners, contractors, subcontractors, creditors, rating agencies and others; bp’s access to future
credit resources; business disruption and crisis management; the impact on bp’s reputation of ethical misconduct and noncompliance with regulatory obligations; trading losses; major uninsured losses; decisions by Rosneft’s management and board of directors; the actions of contractors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; public health situations (including an outbreak of an epidemic or pandemic); wars and acts of terrorism; cyberattacks or sabotage; and other factors discussed elsewhere in this report including under Risk factors (pages 67-70). In addition to factors set forth elsewhere in this report, those set out above are important factors, although not exhaustive, that may cause actual results and developments to differ materially from those expressed or implied by these forward-looking statements.
Statements regarding competitive position
Statements
referring to bp’s competitive position are based on the company’s belief and, in some cases, rely on a range of sources, including investment analysts’ reports, independent market studies and bp’s internal assessments of market share based on publicly available information about the financial results and performance of market participants.
The primary market for the company’s ordinary shares (trading symbol 'BP.'), 8% cumulative first preference shares (trading symbol 'BP.A') and 9% cumulative second preference shares (trading symbol 'BP.B') is the London Stock Exchange (LSE). The
company’s ordinary shares are a constituent element of the Financial Times Stock Exchange 100 Index.
In the US, the company’s securities are listed and traded on the New York Stock Exchange (NYSE) in the form of ADSs (trading symbol 'BP'), for which JPMorgan Chase Bank, N.A. is the depositary (the Depositary) and transfer agent. The Depositary’s principal office is 383 Madison Avenue, Floor 11, New York, NY, 10179, US. Each ADS represents six ordinary shares. ADSs are evidenced by American depositary receipts (ADRs), which may be issued in either certificated or book entry form.
The company's ordinary shares are also traded in the form of a global depositary certificate representing the
company's ordinary shares on the Frankfurt, Hamburg and Dusseldorf Stock Exchanges.
On 25 February 2021, 849,802,947 ADSs (equivalent to approximately 5,098,817,682 ordinary shares or some 25.06% of the total issued share capital, excluding shares held in treasury) were outstanding and were held by approximately 72,535 ADS holders. Of these, about 71,703 had registered addresses in the US at that date. One of the registered holders of ADSs represents approximately 1,087,342 underlying holders.
On 25 February 2021, there were approximately 225,319 ordinary shareholders. Of these shareholders, around 1,539 had registered addresses in the US and held a total of some 4,381,925 ordinary shares.
Since a number of the ordinary shares and ADSs were held by brokers and other nominees, the number of holders in the US may not be representative
of the number of beneficial holders or their respective country of residence.
Dividends
The company’s current policy is to pay interim dividends on a quarterly basis on its ordinary shares.
Its policy is also to announce dividends for ordinary shares in US dollars and state an equivalent sterling dividend. Dividends on the company's ordinary shares will be paid in sterling and on the company's ADSs in US dollars. The rate of exchange used to determine the sterling amount
equivalent is the average of the market exchange rates in London over the four business days prior to the sterling equivalent announcement date. The directors may choose to declare dividends in any currency provided that a sterling equivalent is announced. It is not the company’s intention to change its current policy of announcing dividends on ordinary shares in US dollars.
Information regarding dividends announced and paid by the company on ordinary shares and preference shares is provided in Financial statements – Note 10.
A Scrip Dividend Programme (Scrip Programme) was approved by shareholders in 2010 and was renewed for a further three years at the 2018 AGM. It is proposed that the Scrip Programme be renewed
for a further three years at the 2021 AGM. It enabled the company's ordinary shareholders and ADS holders to elect to receive dividends by way of new fully paid ordinary shares (or ADSs in the case of ADS holders) instead of cash. The operation of the Scrip Programme is always subject to the directors’ decision to make the Scrip Programme offer available in respect of any particular dividend.
The company announced on 29 October 2019 and as part of all subsequent quarterly results announcements made since that the board had suspended the Scrip Programme in respect of those quarterly dividends. Ordinary shareholders and ADS holders (subject to certain exceptions) may be able to participate in dividend reinvestment plans. Any decisions with respect to future
dividends will be made by the board of BP p.l.c. following the end of each quarter.
Future dividends will be dependent on future earnings, the financial condition of the group, the Risk factors set out on page 67 and other matters that may affect the business of the group set out in Our strategy on page 15 and in Liquidity and capital resources on page 306.
The following table shows dividends announced and paid by the company per ADS for the past five years.
Dividends
per ADSa
March
June
September
December
Total
2016
UK
pence
42.08
41.50
45.35
47.59
176.52
US cents
60
60
60
60
240
2017
UK
pence
48.95
46.54
45.73
44.66
185.88
US cents
60
60
60
60
240
2018
UK
pence
43.01
44.66
47.58
48.15
183.40
US cents
60
60
61.50
61.50
243
2019
UK
pence
46.43
48.39
50.09
46.95
191.86
US cents
61.50
61.50
61.50
61.50
246
2020
UK
pence
48.94
50.05
24.26
23.50
146.75
US cents
63.00
63.00
31.50
31.50
189
a Dividends
announced and paid by the company on ordinary and preference shares are provided in Financial statements – Note 10.
There are currently no UK foreign exchange controls or restrictions on remittances of dividends on the ordinary shares or on the conduct of the company’s operations, other than restrictions applicable to certain countries and persons subject to EU economic sanctions or those sanctions adopted by the UK government which implement resolutions of the Security Council of the United Nations.
Shareholder taxation information
This
section describes the material US federal income tax and UK taxation consequences of owning ordinary shares or ADSs to a US holder who holds the ordinary shares or ADSs as capital assets for tax purposes. It does not apply, however, inter alia to members of special classes of holders some of which may be subject to other rules, including: tax-exempt entities, life insurance companies, dealers in securities, traders in securities that elect a mark-to-market method of accounting for securities holdings, investors liable for alternative minimum tax, holders that, directly or indirectly, hold 10% or more of the company’s shares (as measured by voting power or value), holders that hold the shares or ADSs as part of a straddle or a hedging or conversion transaction, holders that purchase or sell the shares or ADSs as part of a wash sale for US federal income tax purposes, or holders whose
functional currency is not the US dollar. In addition, if a partnership holds the shares or ADSs, the US federal income tax treatment of a partner will generally depend on the status of the partner and the tax treatment of the partnership and may not be described fully below.
A US holder is any beneficial owner of ordinary shares or ADSs that is for US federal income tax purposes (1) a citizen or resident of the US, (2) a US domestic corporation, (3) an estate whose income is subject to US federal income taxation regardless of its source, or (4) a trust if a US court can exercise primary supervision over the trust’s administration and one or more US persons are authorized to control all substantial decisions of the trust.
This section is based on the tax laws of the United States, including the Internal Revenue Code of 1986, as amended, its legislative history, existing and proposed
US Treasury regulations thereunder, published rulings and court decisions, and the taxation laws of the UK, all as currently in effect, as well as the income tax convention between the US and the UK that entered into force on 31 March 2003 (the ‘Treaty’). These laws are subject to change, possibly on a retroactive basis. This section further assumes that each obligation under the terms of the deposit agreement relating to bp ADSs and any related agreement will be performed in accordance with its terms.
For purposes of the Treaty and the estate and gift tax Convention (the ‘Estate Tax Convention’) and for US federal income tax and UK taxation purposes, a holder of ADRs evidencing ADSs will be treated as the owner of the company’s ordinary shares represented by those ADRs. Exchanges of ordinary shares for ADRs and ADRs for ordinary shares generally
will not be subject to US federal income tax or to UK taxation other than stamp duty or stamp duty reserve tax, as described below.
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Shareholder
information
Investors should consult their own tax adviser regarding the US federal, state and local, UK and other tax consequences of owning and disposing of ordinary shares and ADSs in their particular circumstances, and in particular whether they are eligible for the benefits of the Treaty in respect of their investment in the shares or ADSs.
Taxation of dividends
UK taxation
Under current UK taxation law, no withholding tax will be deducted from dividends paid by the company, including dividends paid to US holders. A shareholder that is a company resident for tax purposes in the UK or trading in the UK through a permanent establishment generally will
not be taxable in the UK on a dividend it receives from the company. A shareholder who is an individual resident for tax purposes in the UK is subject to UK tax on dividends received from the company, including dividends received under the dividend reinvestment plan (DRIP) for ordinary shareholders, but until 5 April 2016, was entitled to a tax credit on cash dividends paid on ordinary shares or ADSs of the company equal to one-ninth of the cash dividend.
From 6 April 2016 the dividend tax credit was replaced by a new tax-free dividend allowance and dividends paid by the company on or after
6 April 2016 do not carry a UK tax credit. The dividend allowance was £5,000 but this has been reduced to £2,000 as of 6 April 2018.
The dividend allowance of £2,000 means there is no UK tax due on the first £2,000 of dividends received. Dividends above this level are subject to tax at 7.5% for basic tax payers, 32.5% for higher rate tax payers and 38.1% for additional rate tax payers.
Although the first £2,000 of dividend income is not subject to UK income tax, it does not reduce the total income for tax purposes. Dividends within the dividend allowance still count towards basic or higher rate bands, and may therefore affect the rate of tax paid on dividends received in excess of the £2,000 allowance. For instance, if an individual has an annual gross salary of £50,000 and also receives a dividend of £12,000 they will be subject to the following scenario. The individual's personal
allowance and the basic rate tax band will be used up by the gross salary. The remaining part of the salary and the whole of the dividend will be subject to tax at the higher rate, although the dividend allowance will reduce the amount of dividend subject to tax. The dividend of £12,000 will be reduced by the dividend allowance of £2,000 leaving taxable dividend income of £10,000. The dividend will be taxed at 32.5% so that the total tax payable on the dividends is £3,250.
How the shareholder pays the tax arising on the dividend income depends on the amount of dividend income and salary they receive in the tax year. If less than £2,000 they will not need to report anything or pay any tax. If between £2,000 and £10,000, the shareholder can pay what they owe by: contacting the helpline; asking HMRC to change their tax code – the tax will be taken from their wages or pension or through completion of the ‘Dividends’ section of
their tax return, where one is being filed. If over £10,000 they will be required to file a self-assessment tax return and should complete the ‘Dividends’ section with details of the amounts received.
US federal income taxation
A US holder is subject to US federal income taxation on the gross amount of any dividend paid by the company (including dividends paid but reinvested received under the Global Invest Direct (GID) Dividend Reinvestment Plan for ADS holders) out of its current or accumulated earnings and profits (as determined for US federal income tax purposes). Dividends paid to a non-corporate US holder that constitute qualified dividend income will be taxable to the holder at a preferential rate, provided that the holder has a holding period in the ordinary shares or ADSs of more than 60
days during the 121-day period beginning 60 days before the ex-dividend date and meets other holding period requirements. Dividends paid by the company with respect to the ordinary shares or ADSs will generally be qualified dividend income.
For US federal income tax purposes, a dividend must be included in income when the US holder, in the case of ordinary shares, or the Depositary, in the case of ADSs, actually or constructively receives the dividend and will not be eligible for the dividends-received deduction generally allowed to US corporations in respect of dividends received from other US corporations. US ADS holders should consult their own tax
adviser regarding the US tax treatment of the dividend fee in respect of dividends. Dividends will be income
from sources outside the US and generally will be ‘passive category income’ or, in the case of certain US holders, ‘general category income’, each of which is treated separately for purposes of computing a US holder’s foreign tax credit limitation.
As noted above in UK taxation, a US holder will not be subject to UK withholding tax. Accordingly, the receipt of a dividend will not entitle the US holder to a foreign tax credit.
The amount of the dividend distribution on the ordinary shares that is paid in pounds sterling will be the US dollar value of the pounds sterling payments made, determined at the spot pounds sterling/US dollar rate on the date the dividend distribution is includible in income, regardless of whether the payment is, in fact, converted into US dollars. Generally, any gain or loss resulting from currency exchange fluctuations during the period from the date the pounds
sterling dividend payment is includible in income to the date the payment is converted into US dollars will be treated as ordinary income or loss and will not be eligible for the preferential tax rate on qualified dividend income. The gain or loss generally will be income or loss from sources within the US for foreign tax credit limitation purposes.
Distributions in excess of the company’s earnings and profits, as determined for US federal income tax purposes, will be treated as a return of capital to the extent of the US holder’s basis in the ordinary shares or ADSs and thereafter as capital gain, subject to taxation as described in Taxation of capital gains – US federal income taxation section below.
In addition, the taxation of dividends may be subject to the rules for passive foreign investment
companies (PFIC), described below under ‘Taxation of capital gains – US federal income taxation’. Distributions made by a PFIC do not constitute qualified dividend income and are not eligible for the preferential tax rate applicable to such income.
Taxation of capital gains
UK taxation
A US holder may be liable for both UK and US tax in respect of a gain on the disposal of ordinary shares or ADSs if the US holder is (1) resident for tax purposes in the United Kingdom at the date of disposal, (2) if he or she has left the UK for a period not exceeding five complete tax years between the year of departure from and the year of return to the UK and acquired the shares before leaving the UK and was resident in the UK in the previous four out of seven tax years before the year of departure, (3) a US domestic corporation resident in the UK by
reason of its business being managed or controlled in the UK or (4) a citizen of the US that carries on a trade or profession or vocation in the UK through a branch or agency or a corporation that carries on a trade, profession or vocation in the UK, through a permanent establishment, and that has used, held, or acquired the ordinary shares or ADSs for the purposes of such trade, profession or vocation of such branch, agency or permanent establishment. However, such persons may be entitled to a tax credit against their US federal income tax liability for the amount of UK capital gains tax or UK corporation tax on chargeable gains (as the case may be) that is paid in respect of such gain.
Under the Treaty, capital gains on dispositions of ordinary shares or ADSs generally will be subject to tax only in the jurisdiction of residence of the relevant holder as determined under both the laws of the UK and the US and as required
by the terms of the Treaty.
Under the Treaty, individuals who are residents of either the UK or the US and who have been residents of the other jurisdiction (the US or the UK, as the case may be) at any time during the six years immediately preceding the relevant disposal of ordinary shares or ADSs may be subject to tax with respect to capital gains arising from a disposition of ordinary shares or ADSs of the company not only in the jurisdiction of which the holder is resident at the time of the disposition but also in the other jurisdiction.
For gains on or after 23 June 2010, the UK Capital Gains Tax rate will be dependent on the level of an individual’s taxable income. Where total taxable income and gains after all allowable deductions are less than the upper limit of the basic rate income tax
band of £37,500 (for 2020/21), the rate of Capital Gains Tax will be 10%. For gains (and any parts of gains) above that limit the rate will be 20%.
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333
From
6 April 2008, entitlement to the annual exemption is based on an individual’s circumstances (taking into account Domicile status, remittance basis of taxation and number of years in the UK). For individuals who are entitled to the exemption for 2020/21, this has been set at £12,300. Corporation tax on chargeable gains is levied at 19 per cent for companies from 1 April 2017.
US federal income taxation
A US holder who sells or otherwise disposes of ordinary shares or ADSs will recognize a capital gain or loss for US federal income tax purposes equal to the difference between the US dollar value of the amount realized on the disposition and the US holder’s tax basis, determined in US dollars, in the ordinary shares or ADSs. Any such capital gain or loss generally will be long-term gain or loss, subject to tax at a preferential rate for a non-corporate US holder, if the US holder’s
holding period for such ordinary shares or ADSs exceeds one year. The tax basis of shares acquired through reinvested dividends under the GID Dividend Reinvestment Plan for ADS holders) is equal to the fair market value of the stock on the investment date. The holding period for shares acquired under the plan begins the day after the applicable investment date.
Gain or loss from the sale or other disposition of ordinary shares or ADSs will generally be income or loss from sources within the US for foreign tax credit limitation purposes. The deductibility of capital losses is subject to limitations.
We do not believe that ordinary shares or ADSs will be treated as stock of a passive foreign investment company (PFIC) for US federal income tax purposes, but this conclusion is a factual determination that is made annually and thus is subject to change. If we are treated as a PFIC, unless
a US holder elects to be taxed annually on a mark-to-market basis with respect to ordinary shares or ADSs, any gain realized on the sale or other disposition of ordinary shares or ADSs would in general not be treated as capital gain. Instead, a US holder would be treated as if he or she had realized such gain rateably over the holding period for ordinary shares or ADSs and would be taxed at the highest tax rate in effect for each such year to which the gain was allocated, in addition to which an interest charge in respect of the tax attributable to each such year would apply. Certain ‘excess distributions’ would be similarly treated if we were treated as a PFIC.
Additional tax considerations
Scrip Programme
Until the publication of the 2019 third quarter results, the
company had an optional Scrip Programme, wherein holders of bp ordinary shares or ADSs could elect to receive any dividends in the form of new fully paid ordinary shares or ADSs of the company instead of cash. Please consult your tax adviser for the consequences to you.
UK inheritance tax
The Estate Tax Convention applies to inheritance tax. ADSs held by an individual who is domiciled for the purposes of the Estate Tax Convention in the US and is not for the purposes of the Estate Tax Convention a national of the UK will not be subject to UK inheritance tax on the individual’s death or on transfer during the individual’s lifetime unless, among other things, the ADSs are part of the business property of a permanent establishment situated in the UK used for the performance of independent personal
services. In the exceptional case where ADSs are subject to both inheritance tax and US federal gift or estate tax, the Estate Tax Convention generally provides for tax payable in the US to be credited against tax payable in the UK or for tax paid in the UK to be credited against tax payable in the US, based on priority rules set forth in the Estate Tax Convention.
UK stamp duty and stamp duty reserve tax
The statements below relate to what is understood to be the current practice of HM Revenue & Customs in the UK under existing law.
Provided that any instrument of transfer is not executed in the UK and remains at all times outside the UK and the transfer does not relate to any matter or thing done or to be done in the UK, no UK stamp duty is payable on the acquisition or transfer of ADSs. Neither will an agreement to transfer ADSs
in the form of ADRs give rise to a liability to stamp duty reserve tax.
Purchases of ordinary shares, as opposed to ADSs, through the CREST system of paperless share transfers will be subject to stamp duty reserve tax at 0.5%. The charge will arise as soon as there is an agreement for the transfer of the shares (or, in the case of a conditional agreement, when the condition is fulfilled). The stamp duty reserve tax will apply to agreements to transfer ordinary shares even if the agreement is made outside the UK between two non-residents. Purchases of ordinary shares outside the CREST system are subject either to stamp duty at a rate of £5 per £1,000 (or part, unless the stamp duty is less than £5, when no stamp duty is charged), or stamp duty reserve tax at 0.5%. Stamp duty and stamp duty reserve tax are generally the liability of the purchaser.
A
subsequent transfer of ordinary shares to the Depositary’s nominee will give rise to further stamp duty at the rate of £1.50 per £100 (or part) or stamp duty reserve tax at the rate of 1.5% of the value of the ordinary shares at the time of the transfer. For ADR holders electing to receive ADSs instead of cash, after the 2012 first quarter dividend payment, HM Revenue & Customs no longer seeks to impose 1.5% stamp duty reserve tax on issues of UK shares and securities to non-EU clearance services and depositary receipt systems.
Major shareholders
The disclosure of certain major and significant shareholdings in the share capital of the company is governed by the Companies Act
2006, the UK Financial Conduct Authority’s Disclosure Guidance and Transparency Rules (DTR) and the US Securities Exchange Act of 1934.
Register of members holding bp ordinary shares as at 31 December 2020
Range of holdings
Number of ordinary shareholders
Percentage of total ordinary shareholders
Percentage of total ordinary share capital excluding shares held in treasury
a Includes JPMorgan Chase Bank, N.A. holding 25.33% of the total ordinary issued share capital (excluding shares held in treasury) as the approved depositary for ADSs, a breakdown of which is shown in the table below.
Register of holders of
American depositary shares (ADSs) as at 31 December 2020a
b One holder of ADSs represents 1,056,393 approx. underlying shareholders.
As at 31 December 2020 there were also 1,212 preference shareholders.
Preference shareholders represented 0.42% and ordinary shareholders represented 99.58% of the total issued nominal share capital of the company (excluding shares held in treasury) as at that date.
As at 31 December 2020, the company had not received any notifications pursuant to DTR5. The company also did not receive any notifications pursuant to DTR5 between 1 January 2021 and 25 February 2021.
Under the US Securities Exchange Act of 1934 bp is aware of the following interests as at 25 February 2021:
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Annual Report and Form 20-F 2020
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Shareholder information
Holder
Holding of
ordinary
shares
Percentage of ordinary share capital excluding shares held in treasury
JPMorgan Chase Bank N.A., depositary for ADSs, through its nominee Guaranty Nominees Limited
5,098,817,683
25.06
BlackRock, Inc.
1,514,099,140
7.69
The Vanguard Group, Inc
763,396,544
3.75
The
company’s major shareholders do not have different voting rights.
The company has also been notified of the following interests in preference shares as at 25 February 2021:
Holder
Holding of 8% cumulative first preference shares
Percentage of class
The National Farmers Union Mutual Insurance Society Limited
945,000
13.07
Hargreaves
Lansdown Asset Management Limited
698,778
9.66
Interactive Investor Share Dealing Services
573,177
7.92
M & G Investment Management Ltd.
528,150
7.30
Canaccord Genuity Group Inc.
504,162
6.97
Halifax
Share Dealing Services
416,661
5.76
Holder
Holding of 9% cumulative second preference shares
Percentage of class
The National Farmers Union Mutual Insurance Society Limited
987,000
18.03
M
& G Investment Management Ltd.
644,450
11.77
Safra Group
385,000
7.03
Canaccord Genuity Group Inc.
306,605
5.60
As at 25 February 2021, the total preference shares in issue comprised only 0.42% of the
company’s total issued nominal share capital (excluding shares held in treasury), the rest being ordinary shares.
Annual general meeting
The 2021 AGM is scheduled to be held on Wednesday 12 May 2021 at 11.00am. A separate notice convening the meeting is distributed to shareholders, which includes an explanation of the items of business to be considered at the meeting.
All resolutions for which notice has been given will be decided on a poll. Deloitte LLP have expressed their willingness to continue in office as auditors and a resolution for their reappointment is included in the Notice of bp Annual General Meeting 2021.
The following summarizes certain provisions of the company’s Memorandum and Articles of Association and applicable English law. This summary is qualified in its entirety by reference to the UK Companies Act 2006 (the Act) and the company’s Memorandum and Articles of Association. The Memorandum and Articles of Association are available online at bp.com/usefuldocs.
The
company’s Articles of Association may be amended by a special resolution at a general meeting of the shareholders. At the annual general meeting (AGM) held on 21 May 2018 shareholders voted to adopt new Articles of Association to reflect developments in market practice and to provide clarification and additional flexibility where necessary or appropriate.
Objects and purposes
bp is a public company limited by shares, incorporated under the name BP p.l.c. and is registered in England and Wales with the registered number 102498. The provisions regulating the operations of the company,
known as its ‘objects’, were historically stated in a company’s memorandum. The Act abolished the need to have object provisions and so at the AGM held on 15 April 2010 shareholders approved the removal of its objects clause together with all other provisions of its Memorandum that, by virtue of the Act, are treated as forming part of the company’s Articles of Association.
Directors and secretary
The business and affairs of bp shall be managed by the directors. The company’s Articles of Association provide that directors may be appointed
by the existing directors or by the shareholders in a general meeting. Any person appointed by the directors will hold office only until the next general meeting, notice of which is first given after their appointment and will then be eligible for re-election by the shareholders. A director may be removed by bp as provided for by applicable law and shall vacate office in certain circumstances as set out in the Articles of Association. In addition the company may, by special resolution, remove a director before the expiration of his/her period of office and, subject to the Articles of Association, may by ordinary resolution appoint another person to be a director instead. There is no requirement for a director
to retire on reaching any age.
The Articles of Association place a general prohibition on a director voting in respect of any contract or arrangement in which the director has a material interest other than by virtue of such director’s interest in shares in the company. However, in the absence of some other material interest not indicated below, a director is entitled to vote and to be counted in a quorum for the purpose of any vote relating to a resolution concerning the following matters:
•The giving of security or indemnity with respect to any money lent or obligation taken by the director at the
request or benefit of the company or any of its subsidiary undertakings.
•Any proposal in which the director is interested, concerning the underwriting of company securities or debentures or the giving of any security to a third party for a debt or obligation of the company or any of its subsidiary undertakings.
•Any proposal concerning any other company in which the director is interested, directly or indirectly (whether as an officer or shareholder or otherwise) provided that the director and persons connected with such director are not the holder or holders of 1% or more of the voting interest in the shares of such company.
•Any
proposal concerning the purchase or maintenance of any insurance policy under which the director may benefit.
•Any proposal concerning the giving to the director of any other indemnity which is on substantially the same terms as indemnities given or to be given to all of the other directors or to the funding by the company of his expenditure on defending proceedings or the doing by the company of anything to enable the director to avoid incurring such expenditure where all other directors have been given or are to be given substantially the same arrangements.
•Any proposal concerning an arrangement for the benefit of the employees and directors or former employees and
former directors of the company or any of its subsidiary undertakings, including but without being limited to a retirement benefits scheme and an employees’ share scheme, which does not accord to any director any privilege or advantage not generally accorded to the employees or former employees to whom the arrangement relates.
The Act requires a director of a company who is in any way interested in a contract or proposed contract with the company to declare the nature of the director’s interest at a meeting of the directors of the
company. The definition of ‘interest’ includes the interests of spouses, children, companies and trusts. The Act also requires that a director must avoid a situation where a director has, or could have, a direct or indirect interest that conflicts, or possibly may conflict, with the company’s interests. The Act allows directors of public companies to authorize such conflicts where appropriate, if a company’s Articles of Association so permit. bp’s Articles of Association permit the authorization of such conflicts. The directors may exercise all the powers of the company to borrow money, except
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that the amount remaining undischarged of all moneys borrowed by the company shall not, without approval of the shareholders, exceed two times the amount paid up on the share capital plus the aggregate of the amount of the capital and revenue reserves of the company. Variation of the borrowing power of the board may only be affected by amending the Articles
of Association.
Remuneration of non-executive directors shall be determined in the aggregate by resolution of the shareholders. Remuneration of executive directors is determined by the remuneration committee. This committee is made up of non-executive directors only. There is no requirement of share ownership for a director’s qualification.
The Articles of Association provide entitlement to the directors’ pensions and death and disability benefits to the directors’ relations and dependants respectively.
The circumstances in which a director’s office will automatically terminate include: when a director ceases to hold an executive office of the company and the directors
resolve that he should cease to be a director; if a medical practitioner provides an opinion that a director has become incapable of acting as a director and may remain so incapable for a further three months and the directors resolve that he should cease to be a director; and if all of the other directors vote in favour of a resolution stating that the person should cease to be a director.
The company secretary has express powers to delegate any of the powers or discretions conferred on him or her.
Dividend rights; other rights to share in company profits; capital calls
If recommended by the directors of bp, shareholders of bp may, by resolution, declare dividends but no such dividend may be declared in excess of the amount recommended by the directors.
The directors may also pay interim dividends without obtaining shareholder approval. No dividend may be paid other than out of profits available for distribution, as determined under IFRS and the Act. Dividends on ordinary shares are payable only after payment of dividends on bp preference shares. Any dividend unclaimed after a period of 10 years from the date of declaration of such dividend shall be forfeited and reverts to bp. If the company exercises its right to forfeit shares and sells shares belonging to an untraced shareholder then any entitlement to claim dividends or other monies unclaimed in respect of those shares will be for a period of twelve months after the sale. The company may take such steps as the directors decide are appropriate in the circumstances to trace the member entitled and
the sale may be made at such time and on such terms as the directors may decide.
The directors have the power to declare and pay dividends in any currency provided that a sterling equivalent is announced. It is not the company’s intention to change its current policy of paying dividends in US dollars. At the company’s AGM held on 15 April 2010, shareholders approved the introduction of a Scrip Dividend Programme (Scrip Programme) and to include provisions in the Articles of Association to enable the company to operate the Scrip Programme. The Scrip Programme was renewed at the
company’s AGM held on 21 May 2018 for a further three years. The Scrip Programme enables ordinary shareholders and bp ADS holders to elect to receive new fully paid ordinary shares (or bp ADSs in the case of bp ADS holders) instead of cash. The operation of the Scrip Programme is always subject to the directors’ decision to make the scrip offer available in respect of any particular dividend. Should the directors decide not to offer the scrip in respect of any particular dividend, cash will automatically be paid instead. The directors may determine in relation to any scrip dividend plan or programme how the costs of the programme will be met, the minimum number of ordinary shares required in order to be able to participate in the programme and any arrangements to deal with legal and practical difficulties in any particular territory.
Apart from shareholders’ rights to share in bp’s profits by dividend (if any is declared
or announced), the Articles of Association provide that the directors may set aside:
•A special reserve fund out of the balance of profits each year to make up any deficit of cumulative dividend on the bp preference shares.
•A general reserve out of the balance of profits each year, which shall be applicable for any purpose to which the profits of the company may properly be applied. This may include capitalization of such sum, pursuant to an ordinary shareholders’ resolution, and distribution to
shareholders as if it were distributed by way of a dividend on the ordinary shares
or in paying up in full unissued ordinary shares for allotment and distribution as bonus shares.
Any such sums so deposited may be distributed in accordance with the manner of distribution of dividends as described above.
Holders of shares are not subject to calls on capital by the company, provided that the amounts required to be paid on issue have been paid off. All shares are fully paid.
Share transfers and share certificates
The directors may permit transfers to be effected other than by an instrument in writing and that share certificates will not be required to be issued by the company if they are not required by law.
The
company may charge an administrative fee in the event that a shareholder wishes to replace two or more certificates representing shares with a single certificate or wishes to surrender a single certificate and replace it with two or more certificates. All certificates are sent at the member’s risk.
Voting rights
The Articles of Association of the company provide that voting on resolutions at a shareholders’ meeting will be decided on a poll other than resolutions of a procedural nature, which may be decided on a show of hands. If voting is on a poll, every shareholder who is present in person or by proxy has one vote for every ordinary share held and two votes for every £5 in nominal amount of bp preference
shares held. If voting is on a show of hands, each shareholder who is present at the meeting in person or whose duly appointed proxy is present in person will have one vote, regardless of the number of shares held, unless a poll is requested.
Shareholders do not have cumulative voting rights.
For the purposes of determining which persons are entitled to attend or vote at a shareholders’ meeting and how many votes such persons may cast, the company may specify in the notice of the meeting a time, not more than 48 hours before the time of the meeting, by which a person who holds shares in registered form must be entered on the company’s register of members in order to have the right to attend or vote at the meeting
or to appoint a proxy to do so.
Holders on record of ordinary shares may appoint a proxy, including a beneficial owner of those shares, to attend, speak and vote on their behalf at any shareholders’ meeting, provided that a duly completed proxy form is received not less than 48 hours (or such shorter time as the directors may determine) before the time of the meeting or adjourned meeting or, where the poll is to be taken after the date of the meeting, not less than 24 hours (or such shorter time as the directors may determine) before the time of the poll.
Record holders of bp ADSs are also entitled to attend, speak and vote at any shareholders’ meeting of bp by the appointment by the approved depositary, JPMorgan Chase Bank N.A., of them as proxies in respect of the ordinary shares represented by their ADSs. Each such proxy may also appoint a proxy. Alternatively, holders of bp ADSs
are entitled to vote by supplying their voting instructions to the depositary, who will vote the ordinary shares represented by their ADSs in accordance with their instructions.
Proxies may be delivered electronically.
Corporations who are members of the company may appoint one or more persons to act as their representative or representatives at any shareholders’ meeting provided that the company may require a corporate representative to produce a certified copy of the resolution appointing them before they are permitted to exercise their powers.
Matters are transacted at shareholders’ meetings by the proposing and passing of resolutions, of which there are two types: ordinary
or special.
An ordinary resolution requires the affirmative vote of a majority of the votes of those persons voting at a meeting at which there is a quorum. A special resolution requires the affirmative vote of not less than three quarters of the persons voting at a meeting at which there is a quorum. Any AGM requires 21 clear days’ notice. The notice period for any other general meeting is 14 clear days subject to the company obtaining annual shareholder approval, failing which, a 21 clear day notice period will apply.
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Shareholder information
Liquidation rights; redemption provisions
In the event of a liquidation of bp, after payment of all liabilities and applicable deductions under UK laws and subject to the payment of secured creditors, the holders of bp preference shares would be entitled to the sum of (1) the capital paid up on such shares plus, (2) accrued and unpaid dividends
and (3) a premium equal to the higher of (a) 10% of the capital paid up on the bp preference shares and (b) the excess of the average market price over par value of such shares on the LSE during the previous six months. The remaining assets (if any) would be divided pro rata among the holders of ordinary shares.
Without prejudice to any special rights previously conferred on the holders of any class of shares, bp may issue any share with such preferred, deferred or other special rights, or subject to such restrictions as the shareholders by resolution determine (or, in the absence of any such resolutions, by determination of the directors), and may issue shares that are to be or may be redeemed.
Variation of rights
The rights attached to any class of shares may be varied with the consent in writing of holders of 75% of the shares of that
class or on the adoption of a special resolution passed at a separate meeting of the holders of the shares of that class. At every such separate meeting, all of the provisions of the Articles of Association relating to proceedings at a general meeting apply, except that the quorum with respect to a meeting to change the rights attached to the preference shares is 10% or more of the shares of that class, and the quorum to change the rights attached to the ordinary shares is one third or more of the shares of that class.
Shareholders’ meetings and notices
Shareholders must provide bp with a postal or electronic address in the UK to be entitled to receive notice of shareholders’ meetings. Holders of bp ADSs are entitled to receive notices under the terms of the deposit agreement relating to bp ADSs.
The substance and timing of notices are described above under the heading Voting rights.
Under the Act, the AGM of shareholders must be held once every year, within each six month period beginning with the day following the company’s accounting reference date. All general meetings shall be held at a time and place determined by the directors. If any shareholders’ meeting is adjourned for lack of quorum, notice of the time and place of the adjourned meeting may be given in any lawful manner, including electronically. Powers exist for action to be taken either before or at the meeting by authorized officers to ensure its orderly conduct and safety of those attending.
The directors have power to convene a general meeting which is a hybrid meeting, that is to provide facilities for shareholders to attend
a meeting which is being held at a physical place by electronic means as well (but not to convene a purely electronic meeting).
The provisions of the Articles of Association in relation to satellite meetings permit facilities being provided by electronic means to allow those persons at each place to participate in the meeting.
Limitations on voting and shareholding
There are no limitations, either under the laws of the UK or under the company’s Articles of Association, restricting the right of non-resident or foreign owners to hold or vote bp ordinary or preference shares in the
company other than limitations that would generally apply to all of the shareholders and limitations applicable to certain countries and persons subject to EU economic sanctions or those sanctions adopted by the UK government which implement resolutions of the Security Council of the United Nations.
Disclosure of interests in shares
The Act permits a public company to give notice to any person whom the company believes to be or, at any time during the three years prior to the issue of the notice, to have been interested in its voting shares requiring them to disclose certain information with respect to those interests. Failure to supply the information required may lead to disenfranchisement of the relevant shares and a prohibition on their transfer
and receipt of dividends and other payments in respect of those shares and any new shares in the company issued in respect of those shares. In this context the term ‘interest’ is widely defined and will generally include an interest of any kind whatsoever in voting shares, including any interest of a holder of bp ADSs.
Called-up share capital
Details of the allotted, called-up and fully-paid share capital at 31 December 2020 are set out in Financial statements – Note 31. In accordance with institutional investor guidelines, the company deems it appropriate to grant authority to the directors to allot shares and other securities and to disapply pre-emption rights by way of shareholders' resolutions at each AGM in
place of authority granted by virtue of the company's Articles of Association. At the AGM on 27 May 2020, authorization was given to the directors to allot shares in the company and to grant rights to subscribe for, or to convert any
security into, shares in the company up to an aggregate nominal amount as set out in the Notice of Meeting 2020. These authorities were given for the period until the next AGM in 2021 or 27 August 2021, whichever is the earlier. These authorities are renewed annually at the AGM.
Company records and service of notice
In
relation to notices not covered by the Act, the reference to notice by advertisement in a national newspaper also includes advertisements via other means such as a public announcement.
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Purchases
of equity securities by the issuer and affiliated purchasers
In November 2017 bp began a share repurchase or buyback programme (the programme). The sole purpose of the programme was to reduce the issued share capital of the company to offset the ongoing dilutive effect of scrip dividends over time, as announced by the company on 31 October 2017. In January 2020 the share dilution buyback programme had fully offset the impact of scrip dilution since the third quarter 2017. Authorization for the company to make market purchases (as defined in section 693(4) of the Companies Act 2006) of ordinary shares with a nominal value of $0.25 each in the
company was renewed at the company’s 2020 AGM covering the period until the date of the company's 2021 AGM or 27 August 2021, whichever is earlier. The maximum number of ordinary shares to be purchased under this authority will not exceed 2,025,610,110 ordinary shares. The shares purchased will be cancelled.
The following table provides details of ordinary share purchases made (1) under the programme and (2) by the Employee Share Ownership Plans (ESOPs) and other purchases of ordinary shares and ADSs made to satisfy the requirements of certain employee share-based payment plans.
Total
number of shares purchaseda
Average price paid per share $
Number of shares purchased by ESOPs or for certain employee share-based plansb
Number of shares purchased as part of the buyback programmec
Maximun approximate dollar value of shares yet to be purchased under the programme $ million
2020
January 7 - January 28
120,057,464
6.47
Nil
120,057,464
N/A
February
Nil
N/A
March
Nil
N/A
April
Nil
N/A
May
Nil
N/A
June
Nil
N/A
July
Nil
N/A
August
Nil
N/A
September
Nil
N/A
October
Nil
N/A
November
Nil
N/A
December
Nil
N/A
2021
January
11
285,552
3.98
285,552
Nil
N/A
February (to February 26)
Nil
N/A
a All
share purchases were of ordinary shares of 25 cents each and/or ADSs (each representing six ordinary shares) and were on/open market transactions.
bTransactions represent the purchases of ADSs made to satisfy requirements of certain employee share-based payment plans.
cThe company announced its intent to commence the programme on 31 October 2017 and announced further details and commencement of the programme on 15 November 2017. The programme was completed in January 2020. At the AGM on 27 May 2020, authorization was given to the company to repurchase up to 2,025,610,110 ordinary shares, for the period ending on the date of the AGM in 2021
or 27 August 2021, whichever is the earlier. This authorization is renewed annually at the AGM. The total number of ordinary shares repurchased during 2020 under the programme was 120,057,464 at a cost of $776 million (including fees and stamp duty) representing 0.59% of the company’s issued share capital excluding shares held in treasury on 31 December 2020. All ordinary shares repurchased in 2020 under the programme were cancelled in order to reduce the company’s issued share capital.
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Shareholder information
Fees and charges payable by ADS holders
The Depositary collects fees for delivery and surrender of ADSs directly from investors depositing shares or surrendering ADSs for the purpose of withdrawal or from intermediaries acting for them. The Depositary collects
fees for making distributions to investors by deducting those fees from the amounts distributed or by selling a portion of the distributable property to pay the fees.
The charges of the Depositary payable by investors are as follows:
Type of service
Depositary actions
Fee
Depositing or substituting the underlying shares
Issuance of ADSs against the deposit of shares, including deposits and issuances in respect of:
•Exchange of securities or other transactions or event or other distribution affecting the ADSs or deposited securities.
$5.00 per 100 ADSs (or portion thereof) evidenced by the new ADSs delivered.
Selling or exercising rights
Distribution or sale of securities, the fee being an amount equal to the fee for the execution and delivery of ADSs that would have been charged as a result of the deposit of such securities.
$5.00 per 100 ADSs (or portion thereof).
Withdrawing an underlying share
Acceptance of ADSs surrendered for withdrawal
of deposited securities.
$5.00 for each 100 ADSs (or portion thereof) evidenced by the ADSs surrendered.
Expenses of the Depositary
Expenses incurred on behalf of holders in connection with:
•Stock transfer or other taxes and governmental charges.
•Delivery by cable, telex, electronic and facsimile transmission.
•Transfer or registration fees, if applicable, for the registration of transfers of underlying shares.
•Expenses of the Depositary in connection with the conversion of foreign currency into US dollars (which are paid out of such
foreign currency).
Expenses payable are subject to agreement between the company and the Depositary by billing holders or by deducting charges from one or more cash dividends or other cash distributions.
Dividend fees
ADS holders who receive a cash dividend are charged a fee which bp uses to offset the costs associated with administering the ADS programme.
The Deposit Agreement provides that a fee of $0.05 or less per ADS can be charged. The current fee is $0.02 per bp ADS per calendar year (equivalent to $0.005 per bp ADS per quarter per cash distribution).
Global Invest Direct (GID) Plan
New
investors and existing ADS holders can buy, sell or reinvest dividends into further bp ADSs by enrolling in bp’s GID Plan, sponsored and administered by the Depositary.
Cost per transaction is $2.00 for recurring, $2.00 for one-time automatic investments, and $5.00 for investment made by check. Dividend reinvestment is 5% of the dividend amount up to a maximum of $5.00. Purchase trading commission is $0.12 per share.
Fees and payments made by the Depositary to the issuer
The Depositary has agreed to reimburse certain company expenses related to the company’s
ADS programme and incurred by the company in connection with the ADS programme arising during the year ended 31 December 2020. The Depositary reimbursed to the company, or paid amounts on the company’s behalf to third parties, or waived its fees and expenses, of $18,936,081.43 for the year ended 31 December 2020.
The table below sets out the types of expenses that the Depositary has agreed to reimburse and the fees it has agreed to waive for standard costs associated with the administration of the ADS programme relating to the year ended 31 December 2020.
Category
of expense reimbursed, waived or paid directly to third parties
Amount reimbursed, waived or paid directly to third parties for the year ended 31 December 2020
Fees for delivery and surrender of bp ADSs
1,267,682.60
Dividend feesa
17,668,398.83
Total
18,936,081.43
a Dividend fees are charged to ADS holders who receive a cash distribution, which bp uses to offset the costs associated with administering
the ADS programme.
Under certain circumstances, including removal of the Depositary or termination of the ADR programme by the company, the company is required to repay the Depositary certain amounts reimbursed and/or
expenses paid to or on behalf of the company during the 12-month period prior to notice of removal or termination.
Documents on display
The bp
Annual Report and Form 20-F 2020 is available online at bp.com/annualreport. To obtain a hard copy of bp’s complete audited financial statements, free of charge, UK based shareholders should contact bp Distribution Services by calling +44 (0) 800 037 2172 or by emailing bpdistributionservices@bp.com. If based in the US or Canada shareholders should contact Issuer Direct by calling +1 888 301 2505 or by emailing bpreports@issuerdirect.com.
The company is subject
to the information requirements of the US Securities Exchange Act of 1934 applicable to foreign private issuers. In accordance with these requirements, the company files its Annual Report and Form 20-F and other related documents with the SEC. The SEC maintains an internet site at www.sec.gov that contains reports and other information regarding issuers, including bp, that file electronically with the SEC. bp's SEC filings are also available at bp.com/sec. bp discloses in this report (see Corporate governance practices (Form 20-F Item 16G) on page 326) significant ways (if any) in which its corporate governance practices differ from those mandated for US companies under NYSE listing standards.
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Shareholding administration
If you have any queries about the administration of shareholdings, such as change of address, change of ownership, dividend payment options or to change the way you receive your company documents (such as the bp Annual Report and Form 20-F and Notice of bp Annual General Meeting)
please contact the bp Registrar or the bp ADS Depositary.
Record
date (to be eligible for the first quarter interim dividend)
12 May 2021
Annual general meeting
18 Jun 2021
First quarter interim dividend payment for 2021
2 Jul 2021
8% and 9% preference shares record date
27 Jul 2021
Second quarter results announced
30 Jul 2021
8% and 9% preference shares dividend payment
6 Aug 2021
Record
date (to be eligible for the second quarter interim dividend)
24 Sep 2021
Second quarter interim dividend payment for 2021
2 Nov 2021
Third quarter results announced
12 Nov 2021
Record date (to be eligible for the third quarter interim dividend)
17 Dec 2021
Third quarter interim dividend payment for 2021
a All future dates are provisional and may be subject to change. For the full calendar see bp.com/financialcalendar.
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Glossary
Abbreviations
ADR
American depositary receipt.
ADS
American depositary share. 1 ADS = 6 ordinary shares.
Barrel (bbl)
159 litres, 42 US gallons.
bcf
Billion
cubic feet.
bcfe
Billion cubic feet equivalent.
EVP
Executive vice president.
FPSO
Floating production, storage and offloading.
GAAP
Generally accepted accounting practice.
Gas
Natural gas.
gCO2e/MJ
Grams of carbon dioxide equivalent per megajoule of energy.
GHG
Greenhouse gas.
GRI
Global
Reporting Initiative.
GtCO2
Gigatonnes of carbon dioxide.
GWh
Gigawatt hour.
HSSE
Health, safety, security and environment.
IFRS
International Financial Reporting Standards.
Kb/d
Thousand barrels per day.
KPIs
Key performance indicators.
kt
Thousand tonnes.
LNG
Liquefied
natural gas.
LPG
Liquefied petroleum gas.
mb/d
Thousand barrels per day.
Mbbl
Million barrels.
mboe/d
Thousand barrels of oil equivalent per day.
mmb/d
Million barrels per day.
mmboe/d
Million barrels of oil equivalent per day.
mmBtu
Million British thermal units.
mmcf/d
Million
cubic feet per day.
Mte
Million tonnes.
MteCO2e
Million tonnes of CO2 equivalent.
Mtpa
Million tonnes per annum.
NGLs
Natural gas liquids.
PSA
Production-sharing agreement.
PTA
Purified terephthalic acid.
RC
Replacement cost.
SEC
The
United States Securities and Exchange Commission.
TWh
Terawatt hour.
SVP
Senior vice president.
Definitions
Unless the context indicates otherwise, the definitions for the following glossary terms are given below.
Non-GAAP measures are sometimes referred to as alternative performance measures.
CA100+ resolution glossary
CA100+ resolution
The CA100+ resolution means the special resolution requisitioned by Climate Action 100+ and passed at bp’s 2019 Annual General Meeting, the text of which is set out below.
Special resolution: Climate Action 100+ shareholder resolution on climate change disclosures.
That in order to promote the long term success of the company, given the recognised risks and opportunities associated with climate change, we as shareholders direct the company to include in its strategic report and/or other corporate reports, as appropriate, for the year ending 2019 onwards, a description of its strategy which the board considers, in good faith, to be consistent with the goals of Articles
2.1(a)(1) and 4.1(2) of the Paris Agreement(3) (the ‘Paris goals’), as well as:
(1)Capital expenditure: how the company evaluates the consistency of each new material capex investment, including in the exploration, acquisition or development of oil and gas resources and reserves and other energy sources and technologies, with (a) the Paris goals and separately (b) a range of other outcomes relevant to its strategy.
(2) Metrics and targets: the company’s principal metrics and relevant targets or goals over the short, medium and/or long-term, consistent with the Paris goals, together with disclosure of:
a. The anticipated levels of investment
in (i) oil and gas resources and reserves; and (ii) other energy sources and technologies.
b. The company’s targets to promote reductions in its operational greenhouse gas emissions, to be reviewed in line with changing protocols and other relevant factors
c. The estimated carbon intensity of the company’s energy products
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and progress on carbon intensity over time.
d. Any linkage between the above targets and executive remuneration.
(3) Progress reporting: an annual review of progress against (1) and (2) above.
Such disclosure and reporting to include the criteria and summaries of the methodology and core assumptions used, and to omit commercially confidential or competitively sensitive information and be prepared at reasonable cost; and provided that nothing in this resolution shall limit the
company’s powers to set and vary its strategy, or associated targets or metrics, or to take any action which it believes in good faith, would best promote the long-term success of the company.
The Paris goals
(1) Article 2.1(a) of the Paris Agreement states the goal of ‘Holding the increase in the global average temperature to well below 2°C above pre-industrial levels and pursuing efforts to limit the temperature increase to 1.5°C above pre-industrial levels, recognizing that this would significantly reduce the risks and impacts of climate change’.
(2) Article 4.1 of the Paris Agreement: In order to achieve the long-term temperature goal set out in Article 2, parties aim to reach global peaking of greenhouse gas emissions as soon as possible,
recognizing that peaking will take longer for developing country parties, and to undertake rapid reductions thereafter in accordance with best available science, so as to achieve a balance between anthropogenic emissions by sources and removals by sinks of greenhouse gases in the second half of this century, on the basis of equity, and in the context of sustainable development and efforts to eradicate poverty.
(3) U.N. Framework Convention on Climate Change Conference of Parties, Twenty-First Session, Adoption of the Paris Agreement, U.N. Doc. FCCC/CP/2015/L.9/Rev.1 (Dec. 12, 2015).
New material capex investment
For the purposes of the 2020 evaluation discussed on pages 28-32, ‘new material capex investment’ means a decision taken by the resource commitment meeting (RCM) in 2020 to incur
inorganic or organic investments greater than $250 million that relate to a new project or asset, extending an existing project or asset, or acquiring or increasing a share in a project, asset or entity.
There were three investments that met the above criteria in 2020.
Material capex evaluation: Paris-consistency quantitative tests.
For the purposes of evaluating material capex investments for consistency with the Paris goals, two quantitative tests were applied, see page 32.
1.Operational carbon intensity (CI)
The annual average operational GHG emissions (TeCO2e/unit), divided by the relevant unit of output:
•per
thousand barrels of oil equivalent in Upstream
•per utilized equivalent distillation capacity in refining
•per thousand tonnes in petrochemicals.
Net zero aims and ambition glossary
Net zero
References to global net zero in the phrase, 'to help the world get to net zero', means achieving '...a balance between anthropogenic emissions by sources and removals by sinks of greenhouse gases...on the basis of equity, and in the context of sustainable development and efforts to eradicate poverty', as set out in Article 4(1) of the Paris Agreement.
References to net zero for bp in the context of our ambition and Aims 1 and 2 as set out on page 49 (such as 'be a net zero
company by 2050 or sooner'), means achieving a balance between (a) the relevant Scope 1 and 2 emissions (for our Aim 1), or Scope 3 emissions (for our Aim 2), and (b) the aggregate of applicable deductions from qualifying activities such as sinks under our methodology at the applicable time.
Emissions from the carbon in our Upstream oil and gas production
Estimated CO2 emissions from the combustion of upstream production of crude oil, natural gas and natural gas liquids (NGLs) on a bp equity-share basis based on bp’s net share of production, excluding bp’s share of Rosneft production and assuming that all produced volumes undergo full stoichiometric combustion to CO2.
Average emissions intensity of
marketed energy products
The weighted average GHG emissions per unit of energy delivered (in grams CO2e/MJ), estimated in respect of marketing sales of energy products. GHG emissions are estimated on a lifecycle basis covering production, distribution and use of the relevant products (assuming full stoichiometric combustion of the product to CO2).
Methane intensity
Methane intensity refers to the amount of methane emissions from bp’s operated upstream oil and gas assets as a percentage of the total gas that goes to market from those operations. Our methodology is aligned with the Oil and Gas Climate Initiative’s (OGCI).
Sustainable emissions reductions (SER)
SERs result from actions or interventions that have led to ongoing reductions in Scope 1 (direct) and/or Scope 2 (indirect) greenhouse gas (GHG) emissions (carbon dioxide and methane) such that GHG emissions would have been higher in the reporting year if the intervention had not taken place. SERs must meet three criteria: a specific intervention that has reduced GHG emissions, the reduction must be quantifiable and the reduction is expected to be ongoing. Reductions are reportable for a 12-month period from the start of the intervention/action.
Adjusted EBIDA
Non-GAAP measure. Adjusted
EBIDA is defined as underlying replacement cost profit before interest and tax, add back depreciation, depletion and amortization and exploration expenditure written-off (net of non-operating items), less taxation on an underlying RC basis. bp believes that adjusted EBIDA is a useful measure for investors because it is a measure closely tracked by management to evaluate bp’s operating performance and to make financial, strategic and operating decisions and because it may help investors to understand and evaluate, in the same manner as management, the underlying trends in bp’s operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is profit or loss before interest and tax. Adjusted EBIDA per share is calculated based on the shares in issue at period-end.
Adjusted effective tax rate (ETR)
Non-GAAP measure. The adjusted ETR
is calculated by dividing taxation on an underlying replacement cost (RC) basis excluding the impact of reductions in the rate of the UK North Sea supplementary charge in 2016 by underlying RC profit or loss before tax. Taxation on an underlying RC basis is taxation on a RC basis for the period adjusted for taxation on non-operating items and fair value accounting effects, and certain foreign exchange impacts on the group’s tax charge for the period. Information on underlying RC profit or loss is provided below. bp believes it is helpful to disclose the adjusted ETR because this measure may help investors to understand and evaluate, in the same manner as management, the underlying trends in bp’s operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period. A reconciliation to GAAP information is provided on page 348.
Associate
An
entity over which the group has significant influence and that is neither a subsidiary nor a joint arrangement of the group. Significant influence is the power to participate in the financial and operating policy decisions of the investee but is not control or joint control over those policies.
Bioenergy production
Bioenergy production is average thousands of barrels of biofuel production per day during the period covered, net to bp. This includes equivalent ethanol production, bp Bunge biopower for grid export, biogas and refining co-processing and standalone hydrogenated vegetable oil (HVO).
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Brent
A trading classification for North Sea crude oil that serves as a major benchmark price for purchases of oil worldwide.
Capital expenditure
Total cash capital expenditure as stated in the group cash flow statement.
Castrol sales and other operating revenues
Castrol sales and other operating revenues, are sales and other operating revenues generated by our Castrol business.
bp
participates in regional and global commodity trading markets in order to manage, transact and hedge the crude oil, refined products and natural gas that the group either produces or consumes in its manufacturing operations. The range of contracts the group enters into in its commodity trading operations is described below. Using these contracts, in combination with rights to access storage and transportation capacity, allows the group to access advantageous pricing differences between locations, time periods and grades.
Exchange-traded commodity derivatives
Contracts that are typically in the form of futures and
options traded on a recognized exchange, such as Nymex and ICE. Such contracts are traded in standard specifications for the main marker crude oils, such as Brent and West Texas Intermediate; the main product grades, such as gasoline and gasoil; and for natural gas and power. Gains and losses, otherwise referred to as variation margin, are generally settled on a daily basis with the relevant exchange. These contracts are used for the trading and risk management of crude oil, refined products, and natural gas and power. Realized and unrealized gains and losses on exchange-traded commodity derivatives are included in sales and other operating revenues for accounting purposes.
Contracts that are typically in the form of forwards, swaps and options. Some of these contracts are traded bilaterally between counterparties or through brokers, others may be cleared by a central clearing counterparty. These contracts can be used both for trading and risk management activities. Realized and unrealized gains and losses on OTC contracts are included in sales and other operating revenues for accounting purposes. Many grades of crude oil bought and sold use standard contracts
including US domestic light sweet crude oil, commonly referred to as West Texas Intermediate, and a standard North Sea crude blend – Brent, Forties, Oseberg and Ekofisk (BFOE). Forward contracts are used in connection with the purchase of crude oil supplies for refineries and for marketing and sales of the group’s oil production and refined products. The contracts typically contain standard delivery and settlement terms. These transactions call for physical delivery of oil with consequent operational and price risk. However, various means exist and are used from time to time, to settle obligations under the contracts in cash rather than through physical delivery. Physically settled BFOE contracts
delivered by cargo additionally specify a standard volume and tolerance.
Gas and power OTC markets are highly developed in North America and the UK, where commodities can be bought and sold for delivery in future periods. These contracts are negotiated between two parties to purchase and sell gas and power at a specified price, with delivery and settlement at a future date. Typically, the contracts specify delivery terms for the underlying commodity. Some of these transactions are not settled physically as they can be net settled by transacting offsetting sale or purchase contracts for the same location and delivery period. The contracts
contain standard terms such as delivery point, pricing mechanism, settlement terms and specification of the commodity. Typically, volume, price and term (e.g. daily, monthly and balance of month) are the main variable contract terms.
Swaps are typically contractual obligations to exchange cash flows between two parties. A typical swap transaction usually references a floating price and a fixed price with the net difference of the cash flows being settled. Options give the holder the right, but not the obligation, to buy or sell crude, oil products, natural gas or power at a specified price on or before a specific future date. Amounts under these derivative financial instruments are settled at expiry. Typically, netting agreements are used to limit credit exposure and support liquidity.
Spot contracts are contracts to purchase or sell a commodity at the market price prevailing on or around the delivery date when title to the inventory is taken. Term contracts are contracts to purchase or sell a commodity at regular intervals over an agreed term. Though spot and term contracts may have a standard form, there is no offsetting mechanism in place. As such,
these transactions result in physical delivery with operational and price risk. Spot and term contracts typically relate to purchases of crude for a refinery, products for marketing, or third-party natural gas, or sales of the group’s oil production, oil products or gas production to third parties. For accounting purposes, spot and term sales are included in sales and other operating revenues when title passes. Similarly, spot and term purchases are included in purchases for accounting purposes.
Consolidation adjustment – UPII
Unrealized profit in inventory arising on inter-segment transactions.
Convenience gross margin
Non-GAAP measure. Convenience gross margin comprises store gross margin as well as other
merchandise and service contribution, not considered as retail fuels or store gross margin, received from the retail service stations operated under a bp brand, excluding equity-accounted entities.
Convenience, retail fuels and electrification gross margin
Non-GAAP measure. Convenience, retail fuels and electrification gross margin is RC profit before interest and tax for Downstream, adjusted for non-operating items and fair value accounting effects to derive underlying RC profit before interest and tax. Downstream underlying RC profit before interest and tax is further adjusted by subtracting underlying RC profit before interest and tax for the petrochemicals, refining and trading and lubricants businesses; adding-back depreciation, depletion and amortization, production and manufacturing, distribution and administration expenses for fuels (excluding refining and trading); subtracting
earnings from equity-accounted entities in fuels (excluding refining and trading) and gross margin for aviation, B2B and midstream businesses.
Margin share for convenience and electrification is the ratio of convenience and electrification gross margin to total consumer energy (retail fuels and electrification) and convenience gross margin.
bp believes it is helpful to disclose the margin share from convenience and electrification because this measure may help investors to understand and evaluate, in the same way as management, our progress against our strategic objectives of redefining convenience and scaling up our next-gen mobility solutions. The nearest GAAP measures of the numerator and denominator are RC profit before interest and tax. A reconciliation to GAAP information is provided on page 318.
We are unable to present forward-looking
information of the nearest GAAP measures of the numerator and denominator for margin share for convenience and electrification, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to calculate a meaningful comparable GAAP forward-looking financial measure. These items include inventory holding gains or losses, that is difficult to predict in advance in order to include in a GAAP estimate.
Cumulative cash costs reductions
Non-GAAP measure. Cash costs are a subset of production and manufacturing expenses plus distribution and administration expenses and they exclude costs that are classified as non-operating items. They represent the substantial majority of the remaining expenses in these line items but exclude certain costs that are variable, primarily with volumes (such as freight costs). Management believes that cash costs
is a performance measure that provides investors with useful information regarding the company’s financial performance, because it considers these expenses to be the principal operating and overhead expenses that are most directly under their control although they also include certain foreign exchange and commodity price effects. Cumulative cash cost reductions in 2021 compared to 2019, as applicable to the directors’ remuneration usage, are further defined as 2021 exit rate, less agreed portfolio changes compared to 2019 baseline.
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Customer touchpoints
Customer touchpoints are the number of retail customer transactions per day on bp forecourts globally. These include transactions involving fuel and/or convenience across all channels of trade.
Developed renewables to final investment decision (FID)
Total generating capacity for assets developed to FID by all entities where bp has an equity share (proportionate to equity share). If asset is subsequently sold bp will continue to record capacity as developed to FID. If bp equity share increases developed capacity
to FID will increase proportionately to share increase for any assets where bp held equity at the point of FID.
Divestment proceeds
Disposal proceeds as per the group cash flow statement.
Dividend yield
Sum of the four quarterly dividends announced in respect of the year as a percentage of the year-end share price.
Effective tax rate (ETR) on replacement cost (RC) profit or loss
Non-GAAP measure. The ETR on RC profit or loss is calculated by dividing taxation on a RC basis by RC profit or loss before tax. Information on RC profit or loss is provided below. bp believes it is helpful to disclose the ETR on RC profit or loss because this measure excludes the impact of price changes on the replacement of inventories
and allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period. A reconciliation to GAAP information is provided on page 348.
Electric vehicle charge points
Defined as charge points operated by either bp or a bp joint venture.
Fair value accounting effects
Non-GAAP adjustments to our IFRS profit or loss. We use derivative instruments to manage the economic exposure relating to inventories above normal operating requirements of crude oil, natural gas and petroleum products. Under IFRS, these inventories are recorded at historical cost. The related derivative instruments, however, are required to be recorded at fair value with gains and losses recognized in the income statement. This is because
hedge accounting is either not permitted or not followed, principally due to the impracticality of effectiveness-testing requirements. Therefore, measurement differences in relation to recognition of gains and losses occur. Gains and losses on these inventories are not recognized until the commodity is sold in a subsequent accounting period. Gains and losses on the related derivative commodity contracts are recognized in the income statement, from the time the derivative commodity contract is entered into, on a fair value basis using forward prices consistent with the contract maturity.
bp enters into physical commodity contracts
to meet certain business requirements, such as the purchase of crude for a refinery or the sale of bp’s gas production. Under IFRS these physical contracts are treated as derivatives and are required to be fair valued when they are managed as part of a larger portfolio of similar transactions. Gains and losses arising are recognized in the income statement from the time the derivative commodity contract is entered into.
IFRS require that inventory held for trading is recorded at its fair value using period-end spot prices, whereas any related derivative commodity instruments are required to be recorded at values based on forward prices consistent with the contract
maturity. Depending on market conditions, these forward prices can be either higher or lower than spot prices, resulting in measurement differences.
bp enters into contracts for pipelines and other transportation, storage capacity, oil and gas processing and liquefied natural gas (LNG) that, under IFRS, are recorded on an accruals basis. These contracts are risk-managed using a variety of derivative instruments that are fair valued under IFRS. This results in measurement differences in relation to recognition of gains and losses.
The way that bp manages the economic exposures described above, and measures performance internally, differs from the way these activities are measured under IFRS. bp calculates
this difference for consolidated entities by comparing the IFRS result with management’s internal measure of performance. Under management’s internal measure of performance the inventory, transportation and capacity contracts in
question are valued based on fair value using relevant forward prices prevailing at the end of the period. The fair values of derivative instruments used to risk manage certain oil, gas and other contracts, are deferred to match with the underlying exposure and the commodity contracts for business requirements are accounted for on an accruals basis. We believe that disclosing management’s
estimate of this difference provides useful information for investors because it enables investors to see the economic effect of these activities as a whole.
Fair value accounting effects also include changes in the fair value of the near-term portions of LNG contracts that fall within bp’s risk management framework. LNG contracts are not considered derivatives, because there is insufficient market liquidity, and they are therefore accrual accounted under IFRS. However, oil and natural gas derivative financial instruments (used to risk manage the near-term portions of the LNG contracts) are fair valued under IFRS. The fair value accounting effect reduces
timing differences between recognition of the derivative financial instruments used to risk manage the LNG contracts and the recognition of the LNG contracts themselves, which therefore gives a better representation of performance in each period.
In addition, from 2020 fair value accounting effects include changes in the fair value of derivatives entered into by the group to manage currency exposure and interest rate risks relating to hybrid bonds to their respective first call periods. The hybrid bonds which were issued on 17 June 2020 are classified as equity instruments and were recorded in the balance sheet at that date at their USD equivalent issued value. Under IFRS these equity instruments are not remeasured from period to period, and do
not qualify for application of hedge accounting. The derivative instruments relating to the hybrid bonds, however, are required to be recorded at fair value with mark to market gains and losses recognized in the income statement. Therefore, measurement differences in relation to the recognition of gains and losses occur. The fair value accounting effect, which is reported in the Other businesses and corporate segment, eliminates the fair value gains and losses of these derivative financial instruments that are recognized in the income statement. We believe that this gives a better representation of performance, by more appropriately reflecting the economic effect of these risk management activities, in each period.
Finance debt ratio
Finance debt ratio is defined as the ratio of finance debt to the total of finance debt plus total equity.
Free
cash flow
Operating cash flow less net cash used in investing activities and lease liability payments included in financing activities, as presented in the group cash flow statement.
Gearing and net debt
Non-GAAP measures. Net debt is calculated as finance debt, as shown in the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign currency exchange and interest rate risks relating to finance debt, for which hedge accounting is applied, less cash and cash equivalents. Gearing is defined as the ratio of net debt to the total of net debt plus total equity. bp believes these measures provide useful information to investors. Net debt enables investors to see the economic effect of finance debt, related hedges and cash and cash equivalents in total. Gearing enables investors to see how
significant net debt is relative to total equity. The derivatives are reported on the balance sheet within the headings ‘Derivative financial instruments’. See Financial statements – Note 27 for information on finance debt, which is the nearest equivalent measure to net debt on an IFRS basis. The nearest equivalent GAAP measure to gearing on an IFRS basis is finance debt ratio.
We are unable to present reconciliations of forward-looking information for gearing to finance debt ratio, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to present a meaningful comparable GAAP forward-looking financial measure. These items include fair value asset (liability) of hedges related to finance debt and cash and cash equivalents, that are difficult to predict in advance in order to include in a GAAP estimate.
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Gearing including leases and net debt including leases
Non-GAAP measure. Net debt including leases is calculated as net debt plus lease liabilities, less the net amount of partner receivables and payables relating to leases entered into on behalf of joint operations. Gearing including leases is defined as the ratio of net debt including leases to the total of net debt including leases plus total equity. bp believes these measures provide useful information to investors as they enable investors to understand the impact of the group’s lease portfolio on net debt and gearing. See Financial statements – Note 27 for information on finance debt, which is the nearest equivalent
measure to net debt including leases on an IFRS basis. The nearest equivalent GAAP measure to gearing including leases on an IFRS basis is finance debt ratio.
Henry Hub
A distribution hub on the natural gas pipeline system in Erath, Louisiana, that lends its name to the pricing point for natural gas futures contracts traded on the New York Mercantile Exchange and the over-the-counter swaps traded on Intercontinental Exchange.
Hydrocarbons
Liquids and natural gas. Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.
Inorganic capital expenditure
A subset of capital expenditure on
a cash basis and is a non-GAAP measure. Inorganic capital expenditure comprises consideration in business combinations and certain other significant investments made by the group. It is reported on a cash basis. bp believes that this measure provides useful information as it allows investors to understand how bp’s management invests funds in projects which expand the group’s activities through acquisition. Further information and a reconciliation to GAAP information is provided on page 303.
Inventory holding gains and losses
The difference between the cost of sales calculated using the replacement cost of inventory and the cost of sales calculated on the first-in first-out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting, the cost of inventory
charged to the income statement is based on its historical cost of purchase or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant distorting effect on reported income. The amounts disclosed represent the difference between the charge to the income statement for inventory on a FIFO basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen based on the replacement cost of inventory. For this purpose, the replacement cost of inventory is calculated using data from each operation’s production and manufacturing system, either on a monthly basis, or separately for each transaction where the system allows this approach. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions. See
Replacement cost (RC) profit or loss definition below.
Joint arrangement
An arrangement in which two or more parties have joint control.
Joint control
Contractually agreed sharing of control over an arrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control.
Joint operation
A joint arrangement whereby the parties that have joint control of the arrangement have rights to the assets, and obligations for the liabilities, relating to the arrangement.
Joint venture
A joint arrangement whereby the parties that have joint control of the arrangement
have rights to the net assets of the arrangement.
Liquids
Comprises crude oil, condensate and natural gas liquids. For the Upstream segment, it also includes bitumen.
LNG portfolio
LNG portfolio refers to bp group’s LNG equity production plus additional long-term merchant LNG volumes.
LNG train
An LNG train is a processing facility used to liquefy and purify natural gas in the formation of LNG.
Low carbon energy / low carbon technologies
Low carbon (renewable) electricity; bio-energy; electrification; future mobility solutions; carbon capture, use and storage (CCUS); “blue”
or “green” hydrogen; and trading in low carbon products. Note that, while there is some overlap, these terms do not mean the same as bp’s strategic focus area of “low carbon electricity and energy”.
Low carbon investment / investment in low carbon energy / investment in low carbon
Capital expenditure on low carbon energy or technologies.
Low carbon and other energy transition activities
Low carbon energy / technologies as described above, together with convenience; integrated gas and power; bp Ventures and Launchpad.
Major projects
Have a bp net investment of at least $250 million, or are considered to be of strategic importance to bp or of a high degree of complexity.
Margin
share for convenience and electrification
Non-GAAP measure. See Convenience, retail fuels and electrification gross margin definition.
Non-operating items
Charges and credits are included in the financial statements that bp discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management considers not to be part of underlying business operations and are disclosed in order to enable investors better to understand and evaluate the group’s reported financial performance. Non-operating items within equity-accounted earnings are reported net of incremental income tax reported by the equity-accounted entity. An analysis of non-operating items by segment and type is shown on page 304.
Operating cash flow
Net
cash provided by (used in) operating activities as stated in the group cash flow statement. When used in the context of a segment rather than the group, the terms refer to the segment’s share thereof.
Operating cash flow excluding Gulf of Mexico oil spill payments
Non-GAAP measure. It is calculated by excluding post-tax operating cash flows relating to the Gulf of Mexico oil spill from net cash provided by operating activities as reported in the group cash flow statement. bp believes net cash provided by operating activities excluding amounts related to the Gulf of Mexico oil spill is a useful measure as it allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is net cash provided by operating activities.
Operating management system (OMS)
bp’s
OMS helps us manage risks in our operating activities by setting out bp’s principles for good operating practice. It brings together bp requirements on health, safety, security, the environment, social responsibility and operational reliability, as well as related issues, such as maintenance, contractor relations and organizational learning, into a common management system.
Organic capital expenditure
A subset of capital expenditure on a cash basis and is a non-GAAP measure. Organic capital expenditure comprises capital expenditure less inorganic capital expenditure. bp believes that this measure provides useful information as it allows investors to understand how bp’s management invests funds in developing and maintaining the group’s assets. An analysis of organic capital expenditure by segment and region, and a reconciliation to GAAP information is provided on page 303.
We
are unable to present reconciliations of forward-looking information for organic capital expenditure to total cash capital expenditure, because without unreasonable efforts, we are unable to forecast accurately the
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adjusting
item, inorganic capital expenditure, that is difficult to predict in advance in order to derive the nearest GAAP estimate.
An arrangement through which an oil and gas company bears the risks and costs of exploration, development and production. In return, if exploration is successful, the oil company receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of the production remaining after such cost recovery.
Readily marketable inventory (RMI)
RMI is inventory held and price risk-managed by our integrated supply and trading function (IST) which could be sold to generate funds
if required. It comprises oil and oil products for which liquid markets are available and excludes inventory which is required to meet operational requirements and other inventory which is not price risk-managed. RMI is reported at fair value. Inventory held by the Downstream fuels business for the purpose of sales and marketing, and all inventories relating to the lubricants and petrochemicals businesses, are not included in RMI. bp believes that disclosing the amounts of RMI and paid-up RMI is useful to investors as it enables them to better understand and evaluate the group’s inventories and liquidity position by enabling them to see the level of discretionary inventory held by IST and to see builds or releases of liquid trading inventory.
Paid-up RMI excludes RMI which has not yet been paid for. For inventory that is held in storage, a first-in first-out (FIFO) approach is used to determine whether inventory has been paid
for or not. Unpaid RMI is RMI which has not yet been paid for by bp. RMI at fair value, Paid-up RMI and Unpaid RMI are non-GAAP measures. A reconciliation of total inventory as reported on the group balance sheet to paid-up RMI is provided on page 349.
Realizations
Realizations are the result of dividing revenue generated from hydrocarbon sales, excluding revenue generated from purchases made for resale and royalty volumes, by revenue generating hydrocarbon production volumes. Revenue generating hydrocarbon production reflects the bp share of production as adjusted for any production which does not generate revenue. Adjustments may include losses due to shrinkage, amounts consumed during processing, and contractual or regulatory host committed volumes such as royalties. For the Upstream segment, realizations include transfers between businesses.
Refining
availability
Represents Solomon Associates’ operational availability for bp-operated refineries, which is defined as the percentage of the year that a unit is available for processing after subtracting the annualized time lost due to turnaround activity and all planned mechanical, process and regulatory downtime.
Refining marker margin (RMM)
The average of regional indicator margins weighted for bp’s crude refining capacity in each region. Each regional marker margin is based on product yields and a marker crude oil deemed appropriate for the region. The regional indicator margins may not be representative of the margins achieved by bp in any period because of bp’s particular refinery configurations and crude and product slate.
Replacement cost (RC) profit or loss
Reflects
the replacement cost of inventories sold in the period and is arrived at by excluding inventory holding gains and losses from profit or loss. RC profit or loss is the measure of profit or loss that is required to be disclosed for each operating segment under IFRS. RC profit or loss for the group is a non-GAAP measure. Management believes this measure is useful to illustrate to investors the fact that crude oil and product prices can vary significantly from period to period and that the impact on our reported result under IFRS can be significant. Inventory holding gains and losses vary from period to period due to changes in prices as well as changes in underlying inventory levels. In order for investors to understand the operating performance of the group excluding the impact of price changes on the replacement of inventories, and to make comparisons of operating performance between reporting periods, bp’s management believes it is helpful to disclose this measure. The
nearest equivalent measure on an IFRS basis is profit or loss attributable to bp
shareholders. See Financial statements – Note 5. A reconciliation to GAAP information is provided on page 302.
RC profit or loss per share
Non-GAAP measure. Earnings per share is defined in Financial statements – Note 11. RC profit or loss per share is calculated using the same denominator. The numerator used is RC profit or loss attributable to bp shareholders rather than profit or loss attributable to bp shareholders. bp believes it is helpful to disclose the RC profit or loss per share because this measure excludes the impact of price changes on the replacement of inventories and allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is basic earnings
per share based on profit or loss for the period attributable to bp shareholders. A reconciliation to GAAP information is provided on page 348.
Renewables pipeline
Renewable projects satisfying criteria below to the point they can be considered developed to FID :
Site based projects have obtained land exclusivity rights, or for PPA based projects an offer has been made to the counterparty, or for auction projects pre-qualification criteria has been met, or for acquisition projects post a binding offer being accepted.
Reserves replacement ratio
The extent to which the year’s production has been replaced by proved reserves added to our reserve base. The ratio is expressed in oil-equivalent terms and includes changes resulting from discoveries, improved
recovery and extensions and revisions to previous estimates, but excludes changes resulting from acquisitions and disposals.
Retail sites
Retail sites include sites operated by dealers, jobbers, franchisees or brand licensees or joint venture (JV) partners, under the bp brand. These may move to and from the bp brand as their fuel supply agreement or brand licence agreement expires and are renegotiated in the normal course of business. Retail sites are primarily branded bp, ARCO, Amoco, Aral and Thorntons, and also includes sites in India through our Jio-bp JV.
Retail sites in growth markets
These
are retail sites that are either bp branded or co-branded with our partners in China, Mexico and Indonesia and also include sites in India through our Jio-bp JV.
Return on average capital employed
Non-GAAP measure. Return on average capital employed (ROACE) is underlying replacement cost profit, after adding back non-controlling interest and interest expense net of tax (for 2016 and 2017 interest expense was net of notional tax at an assumed 35%), divided by average capital employed (total equity plus finance debt), excluding cash and cash equivalents and goodwill. Interest expense is finance costs excluding lease interest and the unwinding of the discount on provisions and other payables before tax. bp believes it is helpful to disclose the ROACE because this measure gives an indication of the company's
capital efficiency. The nearest GAAP measures of the numerator and denominator are profit or loss for the period attributable to bp shareholders and total equity respectively. The reconciliation of the numerator and denominator is provided on page 349.
We are unable to present forward-looking information of the nearest GAAP measures of the numerator and denominator for ROACE, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to calculate a meaningful comparable GAAP forward-looking financial measure. These items include inventory holding gains or losses and interest net of tax, that are difficult to predict in advance in order to include in a GAAP estimate.
Strategic convenience sites
Strategic convenience sites are retail sites, within the bp portfolio, which both sell bp branded
fuel and carry one of the strategic convenience brands (e.g. M&S, Rewe to Go). To be considered a strategic convenience brand the convenience offer should be a strategic differentiator in the market in which it operates. Strategic convenience site count includes sites under a pilot phase.
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Subsidiary
An
entity that is controlled by the bp group. Control of an investee exists when an investor is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee.
Surplus cash
Surplus cash refers to surplus of sources of cash including operating cash flow, joint venture loan repayments and divestment proceeds, over uses, including leases, Gulf of Mexico oil spill payments, hybrid servicing costs, dividend payments and cash capital expenditure.
Tier 1 and tier 2 process safety events
Tier 1 events are losses of primary containment from a process of greatest consequence – causing harm to a member of the workforce, damage to equipment from a fire or explosion, a community impact or exceeding defined quantities.
Tier 2 events are those of lesser consequence. These represent reported incidents occurring within bp’s operational HSSE reporting boundary. That boundary includes bp’s own operated facilities and certain other locations or situations.
Tight oil and gas
Natural oil and gas reservoirs locked in hard sandstone rocks with low permeability, making the underground formation extremely tight.
Traded electricity
Traded electricity refers to sales data for physically delivered electricity.
Transition and low carbon investments
Capital expenditure on low carbon or other energy transition activities.
UK National Balancing Point
A virtual trading
location for sale, purchase and exchange of UK natural gas. It is the pricing and delivery point for the Intercontinental Exchange natural gas futures contract.
Unconventionals
Resources found in geographic accumulations over a large area, that usually present additional challenges to development such as low permeability or high viscosity. Examples include shale gas and oil, coalbed methane, gas hydrates and natural bitumen deposits. These typically require specialized extraction technology such as hydraulic fracturing or steam injection.
Underlying effective tax rate (ETR)
Non-GAAP measure. The underlying ETR is calculated by dividing taxation on an underlying replacement cost (RC) basis by underlying
RC profit or loss before tax. Taxation on an underlying RC basis is taxation on a RC basis for the period adjusted for taxation on non-operating items and fair value accounting effects, and certain foreign exchange impacts on the group’s tax charge for the period. Information on underlying RC profit or loss is provided below. bp believes it is helpful to disclose the underlying ETR because this measure may help investors to understand and evaluate, in the same manner as management, the underlying trends in bp’s operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period. A reconciliation to GAAP information is provided on page 348.
We are unable to present reconciliations of forward-looking information for underlying ETR to ETR on profit or loss for the period, because without unreasonable efforts, we are unable to forecast accurately
certain adjusting items required to present a meaningful comparable GAAP forward-looking financial measure. These items include the taxation on inventory holding gains and losses, non-operating items and fair value accounting effects, that are difficult to predict in advance in order to include in a GAAP estimate.
Underlying production
Production after adjusting for acquisitions and divestments and entitlement impacts in our production-sharing agreements (PSAs). 2021 underlying production, when compared with 2020, is production after adjusting for acquisitions and divestments, curtailments, and entitlement impacts in our production-sharing agreements/contracts and technical service contract.
Underlying
replacement cost (RC) profit or loss
Non-GAAP measure. RC profit or loss after adjusting for non-operating items and fair value accounting effects. Fair value accounting effects are non-GAAP adjustments. See pages 304 and 305 for additional information on the non-operating items and fair value accounting effects that are used to arrive at underlying RC profit or loss in order to enable a full understanding of the events and their financial impact. bp believes that underlying RC profit or loss is a useful measure for investors because it is a measure closely tracked by management to evaluate bp’s operating performance and to make financial, strategic and operating decisions and because it may help investors to understand and evaluate, in the same manner as management, the underlying trends in bp’s operational performance on a comparable basis, year on year, by adjusting for the effects of these non-operating items and fair
value accounting effects.
The nearest equivalent measure on an IFRS basis for the group is profit or loss for the year attributable to bp shareholders. The nearest equivalent measure on an IFRS basis for segments is RC profit or loss before interest and taxation. A reconciliation to GAAP information is provided on page 302.
Underlying replacement cost (RC) profit or loss per share
Non-GAAP measure. Earnings per share is defined Financial statements – Note 11. Underlying RC profit or loss per share is calculated using the same denominator. The numerator used is underlying RC profit or loss attributable to bp shareholders rather than profit or loss attributable to bp shareholders. bp believes it is helpful to disclose the underlying RC profit or loss per share because this measure may help investors to understand and evaluate, in the same
manner as management, the underlying trends in bp’s operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to bp shareholders. A reconciliation to GAAP information is provided on page 348.
Upstream plant reliability
bp-operated Upstream plant reliability is calculated taking 100% less the ratio of total unplanned plant deferrals divided by installed production capacity. Unplanned plant deferrals are associated with the topside plant and where applicable the subsea equipment (excluding wells and reservoir). Unplanned plant deferrals include breakdowns, which does not include Gulf of Mexico weather related downtime.
Upstream unit production costs
Upstream unit
production costs are calculated as production costs divided by units of production. Production costs do not include ad valorem and severance taxes. Units of production are barrels for liquids and thousands of cubic feet for gas. Amounts disclosed are for bp subsidiaries only and do not include bp’s share of equity-accounted entities.
West Texas Intermediate (WTI)
A light sweet crude oil, priced at Cushing, Oklahoma, which serves as a benchmark price for purchases of oil in the US.
Working capital
Movements in inventories and other current and non-current assets and liabilities as stated in the group cash flow statement.
Trade marks
Trade
marks of the bp group appear throughout this report. They include:
Aral, ARCO, BP, bp pulse, Castrol, Amoco, Thorntons
Trade marks:
Amazon Web Services – a trademark of amazon.com, inc
REWE to Go – a registered trade mark of REWE.
bp Annual Report and Form 20-F 2020
347
Non-GAAP
measures reconciliations
Reconciliation of basic earnings per ordinary share to RC profit (loss) per share and to underlying RC profit per share
Per ordinary share – cents
2020
2019
2018
2017
2016
Profit
(loss) for the yeara
(100.42)
19.84
46.98
17.20
0.61
Inventory holding (gains) losses, before tax
14.18
(3.29)
4.01
(4.32)
(8.52)
Taxation
charge (credit) on inventory holding gains and losses
(3.29)
0.77
(0.99)
1.14
2.58
RC profit (loss) for the year
(89.53)
17.32
50.00
14.02
(5.33)
Net
(favourable) adverse impact of non-operating items and fair value accounting effects, before tax
82.33
40.73
16.93
18.94
35.99
Taxation charge (credit) on non-operating items and fair value accounting effects
(20.94)
(8.81)
(3.23)
(1.65)
(16.87)
Underlying
RC profit for the year
(28.14)
49.24
63.70
31.31
13.79
a Profit attributable to bp shareholders.
Reconciliation of effective tax rate (ETR) to ETR on RC profit or loss and adjusted ETR
Taxation (charge) credit
$
million
2020
2019
2018
2017
2016
Taxation on profit or loss for the year
4,159
(3,964)
(7,145)
(3,712)
2,467
Adjusted
for taxation on inventory holding gains and losses
667
(156)
198
(225)
(483)
Taxation on a RC profit or loss basis
3,492
(3,808)
(7,343)
(3,487)
2,950
Adjusted
for taxation on non-operating items and fair value accounting effects, and certain foreign exchange impacts on the group’s tax charge for the period
4,235
1,788
522
1,184
3,162
Adjusted for the impact of US tax reform
—
—
121
(859)
—
Taxation
on an underlying RC basis
(743)
(5,596)
(7,986)
(3,812)
(212)
Adjusted for the impact of the reduction in the rate of the UK North Sea supplementary charge
—
—
—
—
434
Adjusted
taxation
(743)
(5,596)
(7,986)
(3,812)
(646)
Effective tax rate
%
2020
2019
2018
2017
2016
ETR
on profit or loss for the year
17
49
43
52
107
Adjusted for inventory holding gains and losses
(1)
2
(1)
3
(31)
ETR
on RC profit or loss
16
51
42
55
76
Adjusted for non-operating items and fair value accounting effects, and certain foreign exchange impacts on the group’s tax charge for the period
(30)
(15)
(5)
(9)
(69)
Adjusted
for the impact of US tax reform
—
—
1
(8)
—
Underlying ETR
(14)
36
38
38
7
Adjusted
for the impact of the reduction in the rate of the UK North Sea supplementary charge
—
—
—
—
16
Adjusted ETR
(14)
36
38
38
23
348
bp
Annual Report and Form 20-F 2020
« See Glossary
Return on average capital employed (ROACE)
$ million
2020
2019
2018
2017
2016
Profit
(loss) for the year attributable to bp shareholders
(20,305)
4,026
9,383
3,389
115
Inventory holding (gains) losses, net of tax
2,201
(511)
603
(628)
(1,114)
Non-operating
items and fair value accounting effects, net of tax
12,414
6,475
2,737
3,405
3,584
Underlying RC profit
(5,690)
9,990
12,723
6,166
2,585
Interest
expense, net of taxa
1,402
1,744
1,583
924
635
Non-controlling interests (NCI)
(424)
164
195
79
57
Underlying
RC profit attributable to bp shareholders and NCI, excluding interest expense net of tax
(4,712)
11,898
14,501
7,169
3,277
Total equity
85,568
100,708
101,548
100,404
96,843
Finance
debt
72,664
67,724
65,132
62,574
57,665
Capital employed (2020 average $163,332 million)
158,232
168,432
166,680
162,978
154,508
Less:
Goodwill
12,480
11,868
12,204
11,551
11,194
Cash and cash equivalents
31,111
22,472
22,468
25,586
23,484
114,641
134,092
132,008
125,841
119,830
Average
capital employed excluding goodwill and cash and cash equivalents
124,367
133,050
128,925
122,836
116,333
ROACE
(3.8)
%
8.9
%
11.2
%
5.8
%
2.8
%
a Calculated
on a post-tax basis (for 2017 and earlier interest expense was net of notional tax at an assumed 35%).
Readily marketable inventory (RMI)
Readily marketable inventory (RMI) is oil and oil products inventory held and price risk-managed by bp's integrated supply and trading function (IST) which could be sold to generate funds if required. Details of RMI balances and a reconciliation to GAAP information is set out below. Further information on RMI, RMI at fair value, paid-up RMI and unpaid RMI is provided on page 345.
At 31 December
$ million
2020
2019
RMI
at fair value
6,528
6,837
Paid-up RMI
3,365
3,217
Reconciliation of non-GAAP information
At 31 December
$ million
2020
2019
Reconciliation
of total inventory to paid-up RMI
Inventories as reported on the group balance sheet
16,873
20,880
Less: (a) inventories which are not oil and oil products and (b) oil and oil product inventories which are not risk-managed by IST
(10,810)
(14,280)
RMI on IFRS basis
6,063
6,600
Plus:
difference between RMI at fair value and RMI on an IFRS basis
465
237
RMI at fair value
6,528
6,837
Less: unpaid RMI at fair value
(3,163)
(3,620)
Paid-up RMI
3,365
3,217
The
Directors’ report on pages 71-102, 105 (in respect of the remuneration committee report shown in grey only), 231-258 and 301-349 was approved by the board and signed on its behalf by Ben J. S. Mathews, company secretary on 22 March 2021.
BP p.l.c.
Registered in England and Wales No. 102498
« See Glossary
bp
Annual Report and Form 20-F 2020
349
Signatures
The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.
Quantitative and Qualitative Disclosures about Market Risk
206-211
Item 12.
Description of securities other than equity securities
A.
Debt
Securities
n/a
B.
Warrants and Rights
n/a
C.
Other Securities
n/a
D.
American
Depositary Shares
339
Item 13.
Defaults, Dividend Arrearages and Delinquencies
None
Item 14.
Material Modifications to the Rights of Security Holders and Use of Proceeds
None
Item
15.
Controls and Procedures
154, 326-327
Item 16A.
Audit Committee Financial Expert
76, 94-99
Item 16B.
Code of Ethics
326
Item
16C.
Principal Accountant Fees and Services
96-97, 229, 327
Item 16D.
Exemptions from the Listing Standards for Audit Committees
n/a
Item 16E.
Purchases of Equity Securities
by the Issuer and Affiliated Purchasers
338
Item 16F.
Change in Registrant’s Certifying Accountant
n/a
Item 16G.
Corporate governance
326
Item 17.
Financial
Statements
n/a
Item 18.
Financial Statements
155-159
Item 19.
Exhibits
352
bp
Annual Report and Form 20-F 2020
351
Information about this report
This document constitutes the Annual Report and Accounts in accordance with UK requirements and the Annual Report on Form 20-F in accordance with the US Securities Exchange Act of 1934, for BP p.l.c. for the year ended 31 December 2020. A cross reference to Form 20-F requirements is included on page 351.
This document contains the Strategic report on the inside front cover and pages 1-70 and the Directors’
report on pages 71-102, 105 (in part only), 231-258 and 301-349. The Strategic report and the Directors’ report together include the management report required by DTR 4.1 of the UK Financial Conduct Authority’s Disclosure Guidance and Transparency Rules. The Directors’ remuneration report is on pages 103-126. The consolidated financial statements of the group are on pages 129-230 and the corresponding reports of the auditor are on pages 150-154.
bp Annual Report and Form 20-F 2020 may be downloaded from bp.com/annualreport. No material on the bp website, other than the items identified as bp Annual Report and Form 20-F 2020, forms
any part of this document. References in this document to other documents on the bp website, such as bp Energy Outlook, bp Sustainability Report, bp Statistical Review of World Energy and bp Technology Outlook are included as an aid to their location and are not incorporated by reference into this document.
BP p.l.c. is the parent company of the bp group of companies. The company was incorporated in 1909 in England and Wales and
changed its name to BP p.l.c. in 2001. Where we refer to the company, we mean BP p.l.c. The company and each of its subsidiaries« are separate legal entities. Unless otherwise stated or the context otherwise requires, the term “BP” or "bp" and terms such as “we”, “us” and “our” are used in this report for convenience to refer to one or more of the members of the bp group instead of identifying a particular entity or entities. Information in this document reflects 100% of the assets and operations of the company and its subsidiaries
that were consolidated at the date or for the periods indicated, including non-controlling interests.
The company’s primary share listing is the London Stock Exchange. In the US, the company’s securities are traded on the New York Stock Exchange (NYSE) in the form of ADSs (see page 332 for more details) and in Germany in the form of a global depositary certificate representing bp ordinary shares traded on the Frankfurt, Hamburg and Dusseldorf Stock Exchanges.
The term ‘shareholder’ in this report means, unless the context otherwise requires, investors in the equity capital of BP p.l.c., both direct and indirect. As the
company's shares, in the form of ADSs, are listed on the NYSE, an Annual Report on Form 20-F is filed with the SEC. Ordinary shares are ordinary fully paid shares in BP p.l.c. of 25 cents each. Preference shares are cumulative first preference shares and cumulative second preference shares in BP p.l.c. of £1 each.
Registered in England and Wales No. 102498. London Stock Exchange symbol ‘BP.’
Exhibits
The
following documents are filed in the Securities and Exchange Commission (SEC) EDGAR system, as part of this Annual Report on Form 20-F, and can be viewed on the SEC’s website.
Included only in the annual report filed in the Securities and Exchange Commission EDGAR system.
The total amount of long-term securities of BP p.l.c. and its subsidiaries under any one instrument does not exceed 10% of their
total assets on a consolidated basis.
The company agrees to furnish copies of any or all such instruments to the SEC on request.
Paper: Nautilus Super White is a premium ecological paper. It is made from 100% post-consumer waste recycled paper and is FSC® (Forest Stewardship Council®) certified. The paper also holds the EU Ecolabel certification. The manufacturing mill also holds ISO 14001 environmental certification. Printed in the UK by Pureprint Group.
