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As Of Filer Filing For·On·As Docs:Size Issuer Filing Agent 4/22/21 Cnooc Ltd. 20-F 12/31/20 178:20M Davis Polk & … LLP 01/FA |
Document/Exhibit Description Pages Size
1: 20-F Annual or Annual-Transition Report by a Foreign HTML 1.85M
Non-Canadian Issuer
2: EX-8.1 Opinion of Counsel re: Tax Matters HTML 64K
6: EX-13.1 Annual or Quarterly Report to Security Holders HTML 44K
3: EX-11.1 Statement re: the Computation of Earnings Per HTML 100K
Share
4: EX-12.1 Statement re: the Computation of Ratios HTML 47K
5: EX-12.2 Statement re: the Computation of Ratios HTML 47K
7: EX-15.1 Letter re: Unaudited Interim Financial Info HTML 129K
16: EX-15.10 Letter re: Unaudited Interim Financial Info HTML 42K
17: EX-15.11 Letter re: Unaudited Interim Financial Info HTML 42K
18: EX-15.12 Letter re: Unaudited Interim Financial Info HTML 43K
8: EX-15.2 Letter re: Unaudited Interim Financial Info HTML 127K
9: EX-15.3 Letter re: Unaudited Interim Financial Info HTML 123K
10: EX-15.4 Letter re: Unaudited Interim Financial Info HTML 84K
11: EX-15.5 Letter re: Unaudited Interim Financial Info HTML 82K
12: EX-15.6 Letter re: Unaudited Interim Financial Info HTML 67K
13: EX-15.7 Letter re: Unaudited Interim Financial Info HTML 44K
14: EX-15.8 Letter re: Unaudited Interim Financial Info HTML 43K
15: EX-15.9 Letter re: Unaudited Interim Financial Info HTML 43K
25: R1 Document and Entity Information HTML 83K
26: R2 Consolidated Statements of Profit or Loss and HTML 136K
Other Comprehensive Income
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28: R4 Consolidated Statements of Changes in Equity HTML 100K
29: R5 Consolidated Statements of Cash Flows HTML 118K
30: R6 Corporate Information HTML 151K
31: R7 Statement of Compliance HTML 46K
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33: R9 Summary of Significant Accounting Policies HTML 177K
34: R10 Acquisition and Other Venture HTML 49K
35: R11 Oil and Gas Sales and Marketing Revenues HTML 57K
36: R12 Segment Information HTML 234K
37: R13 Profit Before Tax HTML 115K
38: R14 Finance Costs HTML 83K
39: R15 Key Management Personnel's Remuneration HTML 267K
40: R16 Five Highest Paid Employees HTML 83K
41: R17 Tax HTML 157K
42: R18 Earnings Per Share HTML 72K
43: R19 Dividends HTML 61K
44: R20 Property, Plant and Equipment HTML 119K
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53: R29 Cash and Cash Equivalents and Time Deposits With HTML 47K
Maturity Over Three Months
54: R30 Trade and Accrued Payables HTML 46K
55: R31 Contract Liabilities HTML 50K
56: R32 Other Payables and Accrued Liabilities HTML 54K
57: R33 Loans and Borrowings HTML 178K
58: R34 Lease Liabilities HTML 53K
59: R35 Provision for Dismantlement HTML 70K
60: R36 Share Capital HTML 99K
61: R37 Reserves HTML 49K
62: R38 Related Party Transactions HTML 155K
63: R39 Retirement Benefits HTML 47K
64: R40 Note to the Consolidated Statement of Cash Flows HTML 106K
65: R41 Commitments and Contingencies HTML 57K
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70: R46 Subsequent Events HTML 46K
71: R47 Approval of the Financial Statements HTML 46K
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75: R51 Segment Information (Tables) HTML 230K
76: R52 Profit Before Tax (Tables) HTML 116K
77: R53 Finance Costs (Tables) HTML 82K
78: R54 Key Management Personnel's Remuneration (Tables) HTML 267K
79: R55 Five Highest Paid Employees (Tables) HTML 83K
80: R56 Tax (Tables) HTML 148K
81: R57 Earnings Per Share (Tables) HTML 72K
82: R58 Dividends (Tables) HTML 59K
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(Tables)
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(Tables)
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103: R79 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - HTML 50K
Impairment of financial assets (Details)
104: R80 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Cash HTML 46K
and cash equivalents (Details)
105: R81 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - HTML 44K
Share-based payment transactions (Details)
106: R82 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - HTML 46K
Leases (Details)
107: R83 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - HTML 45K
Convenience translation (Details)
108: R84 ACQUISITION AND OTHER VENTURE - Share purchase HTML 61K
agreement (Details)
109: R85 ACQUISITION AND OTHER VENTURE - Equity transfer HTML 49K
agreement (Details)
110: R86 Oil and Gas Sales and Marketing Revenues (Details) HTML 60K
111: R87 SEGMENT INFORMATION - Segment results (Details) HTML 153K
112: R88 SEGMENT INFORMATION - Geographical information HTML 70K
(Details)
113: R89 SEGMENT INFORMATION - Information about major HTML 54K
customers (Details)
114: R90 Profit Before Tax (Details) HTML 102K
115: R91 Finance Costs (Details) HTML 64K
116: R92 Finance Costs - Narrative (Details) HTML 49K
117: R93 KEY MANAGEMENT PERSONNEL'S REMUNERATION - HTML 124K
Directors' remuneration (Details)
118: R94 KEY MANAGEMENT PERSONNEL'S REMUNERATION - Other HTML 60K
key management personnel's (excluding Directors')
remuneration (Details)
119: R95 FIVE HIGHEST PAID EMPLOYEES - Details of HTML 59K
remuneration (Details)
120: R96 FIVE HIGHEST PAID EMPLOYEES - Number of highest HTML 64K
paid employees in each remuneration band (Details)
121: R97 TAX - Income tax - Narrative (Details) HTML 79K
122: R98 TAX - Analysis of tax expense in the Group's HTML 60K
consolidated statement of profit or loss and other
comprehensive income (Details)
123: R99 TAX - Reconciliation of the PRC statutory HTML 60K
corporate income tax rate to the effective income
tax rate (Details)
124: R100 TAX - Movements of deferred tax liabilities net of HTML 55K
deferred tax assets (Details)
125: R101 TAX - Principal components of deferred tax HTML 93K
balances (Details)
126: R102 TAX - Other taxes (Details) HTML 62K
127: R103 TAX - Special Oil Gain Levy (Details) HTML 53K
128: R104 Earnings Per Share (Details) HTML 63K
129: R105 Dividends (Details) HTML 62K
130: R106 Property, Plant and Equipment (Details) HTML 90K
131: R107 Property, Plant and Equipment - Narrative HTML 67K
(Details)
132: R108 Right-Of-Use Assets (Details) HTML 126K
133: R109 Intangible Assets (Details) HTML 123K
134: R110 INVESTMENTS IN ASSOCIATES - Particulars of HTML 73K
principal associates (Details)
135: R111 INVESTMENTS IN ASSOCIATES - The Group's HTML 48K
investments in associates (Details)
136: R112 INVESTMENTS IN ASSOCIATES - The Groups share of HTML 56K
the profits and other comprehensive income of its
associates in the consolidated financial
statements (Details)
137: R113 INVESTMENT IN A JOINT VENTURE - Particulars of the HTML 59K
joint venture (Details)
138: R114 INVESTMENT IN A JOINT VENTURE - Summarized HTML 99K
financial information of the joint venture
(Details)
139: R115 EQUITY INVESTMENTS AND OTHER FINANCIAL ASSETS - HTML 64K
Equity investments (Details)
140: R116 EQUITY INVESTMENTS AND OTHER FINANCIAL ASSETS - HTML 51K
Other financial assets (Details)
141: R117 EQUITY INVESTMENTS AND OTHER FINANCIAL ASSETS - HTML 48K
Narrative (Details)
142: R118 Other Non-Current Assets (Details) HTML 44K
143: R119 Inventories and Supplies (Details) HTML 52K
144: R120 Trade Receivables (Details) HTML 48K
145: R121 Cash and Cash Equivalents and Time Deposits With HTML 49K
Maturity Over Three Months (Details)
146: R122 Trade and Accrued Payables (Details) HTML 46K
147: R123 Contract Liabilities (Details) HTML 50K
148: R124 Other Payables and Accrued Liabilities (Details) HTML 61K
149: R125 LOANS AND BORROWINGS - Current (Details) HTML 112K
150: R126 LOANS AND BORROWINGS - Non-current (Details) HTML 96K
151: R127 LOANS AND BORROWINGS - Details of notes (Details) HTML 116K
152: R128 LOANS AND BORROWINGS - Narrative (Details) HTML 68K
153: R129 LOANS AND BORROWINGS - Maturities of long term HTML 61K
loans (Details)
154: R130 LOANS AND BORROWINGS - Supplemental information HTML 53K
with respect to long term loans (Details)
155: R131 Lease Liabilities (Details) HTML 65K
156: R132 Provision for Dismantlement (Details) HTML 73K
157: R133 SHARE CAPITAL - Issued share capital (Details) HTML 49K
158: R134 SHARE CAPITAL - Share option schemes - Narrative HTML 63K
(Details)
159: R135 SHARE CAPITAL - Details of share option schemes HTML 75K
(Details)
160: R136 Reserves (Details) HTML 46K
161: R137 RELATED PARTY TRANSACTIONS - Narrative (Details) HTML 47K
162: R138 RELATED PARTY TRANSACTIONS - A summary of HTML 150K
significant related party transactions (Details)
163: R139 Retirement Benefits (Details) HTML 57K
164: R140 Note to the Consolidated Statement of Cash Flows HTML 81K
(Details)
165: R141 Note to the Consolidated Statement of Cash Flows - HTML 72K
Reconciliation of liabilities arising from
financing activities (Details)
166: R142 COMMITMENTS AND CONTINGENCIES - Capital HTML 53K
commitments (Details)
167: R143 FINANCIAL INSTRUMENTS - Fair value of financial HTML 44K
instruments - Narrative (Details)
168: R144 FINANCIAL INSTRUMENTS - Fair value hierarchy - HTML 84K
Assets (Details)
169: R145 FINANCIAL INSTRUMENTS - Fair value hierarchy - HTML 45K
Transfer between different levels of fair value
hierarchy (Details)
170: R146 Concentration of Customers (Details) HTML 61K
171: R147 FINANCIAL RISK MANAGEMENT OBJECTIVES AND POLICIES HTML 55K
- Credit risk and management assessment (Details)
172: R148 FINANCIAL RISK MANAGEMENT OBJECTIVES AND POLICIES HTML 55K
- Currency risk (Details)
173: R149 FINANCIAL RISK MANAGEMENT OBJECTIVES AND POLICIES HTML 48K
- Interest rate risk (Details)
174: R150 FINANCIAL RISK MANAGEMENT OBJECTIVES AND POLICIES HTML 47K
- Liquidity risk (Details)
175: R151 FINANCIAL RISK MANAGEMENT OBJECTIVES AND POLICIES HTML 58K
- Capital management (Details)
177: XML IDEA XML File -- Filing Summary XML 319K
176: EXCEL IDEA Workbook of Financial Reports XLSX 235K
19: EX-101.INS XBRL Instance -- ceo-20201231 XML 6.94M
21: EX-101.CAL XBRL Calculations -- ceo-20201231_cal XML 391K
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Exhibit 15.5
CNOOC Limited
c/o Suite 2300, 500 Centre St. S.
Calgary, Alberta, Canada
T2G 1A6
Re: Report of Third Party for CNOOC Limited’s interest in the Liza Field
Offshore Guyana
Ladies and Gentlemen:
Pursuant
to your request, this report of third party presents a reserves audit, as of December 31, 2020, of the estimated net proved oil, condensate,
natural gas liquids (NGL), and gas reserves of the Liza field located offshore Guyana with interests represented to be held by CNOOC
Limited (CNOOC). This reserves audit was completed on January 22, 2021. CNOOC has represented that these properties account for approximately
3 percent on a net equivalent barrel basis of CNOOC’s net proved reserves as of December 31, 2020, and that the net proved reserves
estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a)
(1)–(32) of Regulation S–X of the United States Securities and Exchange Commission (SEC). It is our opinion that the procedures
and methodologies employed by CNOOC for the preparation of its proved reserves estimates as of December 31, 2020, comply with the current
requirements of the SEC. We have reviewed information provided by CNOOC Petroleum Guyana Limited (CPG), a subsidiary of CNOOC, that it
represents to be CNOOC’s estimates of the net reserves, as of December 31, 2020, for the same properties as those which we evaluated.
This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S–K and is to be used for inclusion
in certain SEC filings by CNOOC.
Reserves
estimates included herein are expressed as net reserves as represented by CPG. Gross reserves are defined as the total estimated petroleum
remaining to be produced from this field after December 31, 2020. Net reserves are
defined as that portion of the gross reserves attributable to the interests held by CNOOC after deducting all interests held by others.
The Liza field in which CNOOC holds an interest is subject to the terms of a Petroleum Agreement between the Government of the Cooperative Republic of Guyana and the joint venture participants. The terms of these agreements generally allow for working interest participants to be reimbursed for portions of capital costs and operating expenses and to share in the profits. The reimbursements and profit proceeds are converted to a barrel of oil equivalent or cubic foot of gas equivalent by dividing by product prices to estimate the “entitlement reserves.” These entitlement reserves are equivalent in principle to net reserves and are used to calculate an equivalent net share, termed an “entitlement interest.” In this report, CNOOC reserves or interest in these properties subject to this production sharing agreement is the entitlement based on CNOOC’s working interest.
Estimates of reserves should be regarded only as estimates that may change as further production history and additional information become available. Not only are such estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.
Information used in this reserves audit was obtained from reviews with CPG personnel and from CPG files. In the preparation of this report we have relied upon such information furnished by CPG with respect to the property interests being evaluated, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. Furthermore, if in the course of our examination something came to our attention that brought into question the validity or sufficiency of any such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or had independently verified such information or data. In our opinion, the adequacy and quality of the data provided to us were sufficient for us to conduct this reserves audit. A field examination was not considered necessary for the purposes of this report.
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Definition of Reserves
Petroleum reserves estimated by CNOOC included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used by CNOOC in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:
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)
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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 favorable than in the reservoir as a whole, the operation of an installed program 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 program was based; and, (B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic and operating 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.
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
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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.
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, as defined in Rule 4-10(a)(2) of Regulation S-X, or by other evidence using reliable technology establishing reasonable certainty.
Methodology and Procedures
Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with practices generally recognized by the petroleum industry as
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presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019.” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.
Based on the current stage of field development, production performance, the development plans provided by CPG on behalf of CNOOC, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.
The proved undeveloped reserves estimates were based on opportunities identified in the plan of development provided by CPG on behalf of CNOOC.
CPG has represented that CNOOC’s senior management is committed to the Liza Phase 1 and Phase 2 development plan provided by CPG on behalf of CNOOC and that CNOOC has the financial capability to execute the development plan, including the drilling and completion of wells and the installation of equipment and facilities.
The volumetric method was used to estimate the original oil in place (OOIP). Structure maps were prepared to delineate each reservoir, and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation.
Estimates of ultimate recovery were obtained after applying recovery factors to OOIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material balance and other engineering methods were used to estimate recovery factors based on an analysis of reservoir performance, including production rate, reservoir pressure, and reservoir fluid properties.
For cases where history-matched dynamic models were available and applicable, model results were used to estimate recovery factors and reserves production forecasts.
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For certain cases, reserves were estimated by incorporating elements of analogy with similar wells or reservoirs for which more complete data was available.
Petroleum reserves estimated by CNOOC and evaluated by DeGolyer and MacNaughton are classified as proved and are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming the continuation of current regulatory practices using conventional production methods and equipment. Reserves were estimated only to the limit of economic production as defined under the Definitions of Reserves heading of this report and prior to the expiration of the 20-year production period of the Petroleum Agreement.
Data provided by CPG from wells drilled through December 31, 2020, and made available for this reserves audit were used to prepare the reserves estimates herein. These reserves estimates were based on consideration of monthly production data available only through October 25, 2020. Estimated cumulative production, as of December 31, 2020, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for approximately 2 months.
Oil and condensate reserves estimated herein are those to be recovered by normal field separation. NGL reserves estimated herein include C5+ and liquefied petroleum gas (LPG), which consists primarily of propane and butane fractions, and are the result of low-temperature plant processing. Oil, condensate, and NGL reserves included in this report are expressed in thousands of barrels (103bbl). In these estimates, 1 barrel equals 42 United States gallons. For reporting purposes, oil and condensate reserves have been estimated separately and are presented herein as a summed quantity.
Currently, there are no plans to process produced gas to recover condensate or NGL; therefore, condensate and NGL reserves were estimated herein to be zero.
Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and processing. Gas reserves estimated herein are reported as sales gas. Gas quantities are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at a pressure
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base of 14.7 pounds per square inch absolute (psia). Gas quantities included in this report are expressed in millions of cubic feet (106ft3).
Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial reservoir conditions with no oil present in the reservoir. Associated gas includes both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in oil at initial reservoir conditions. All gas quantities estimated herein are associated solution gas.
Currently, there is no market for gas sales from the Liza field; therefore, sales gas reserves were estimated herein to be zero.
At the request of CPG on behalf of CNOOC, sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.
Primary Economic Assumptions
This report has been prepared using initial prices, expenses, and costs provided by CPG on behalf of CNOOC in United States dollars (U.S.$). Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic assumptions were used for estimating the reserves reported herein:
Oil Prices
CPG, on behalf of CNOOC, has represented that the oil prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements. To account for quality and transportation costs, CPG, on behalf of CNOOC, provided price differentials to a Brent reference price of U.S.$42.18 per barrel and the prices were held constant thereafter. The volume-weighted average price attributable to the estimated proved reserves over the life of the field was U.S.$41.33 per barrel of oil.
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Operating Expenses, Capital Costs, and Abandonment Costs
Estimates of operating expenses, provided by CPG on behalf of CNOOC and based on current expenses, were held constant for the lives of the properties. Future capital expenditures were estimated using 2020 values, provided by CPG on behalf of CNOOC, and were not adjusted for inflation. In certain cases, future expenditures, either higher or lower than current expenditures, may have been used because of anticipated changes in operating conditions, but no general escalation that might result from inflation was applied. Abandonment costs, which are those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment, were provided by CPG on behalf of CNOOC and were not adjusted for inflation. Operating expenses, capital costs, and abandonment costs were considered, as appropriate, in determining the economic viability of undeveloped reserves estimated herein.
In our opinion, the information relating to estimated proved reserves of oil, condensate, natural gas liquids, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, and 932-235-50-9, of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a)(1), (2), (3), (4), (5), (8), and 1203(a) of Regulation S–K of the Securities and Exchange Commission, provided however, that estimates of proved developed and proved undeveloped reserves are not presented at the beginning of the year.
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Summary of Conclusions
CPG, on behalf of CNOOC, has represented that its estimated net proved reserves attributable to the evaluated properties were based on the definition of proved reserves of the SEC. The CNOOC net proved reserves attributable to the Liza field offshore Guyana, as of December 31, 2020, and which represent approximately 3 percent of total CNOOC net reserves on a net equivalent barrel basis, are summarized as follows, expressed in thousands of barrels (103bbl), millions of cubic feet (106ft3), and thousands of barrels of oil equivalent (103boe):
Estimated by CNOOC Net Proved Reserves | ||||||||
Oil and Condensate (103bbl) |
NGL (103bbl) |
Sales Gas (106ft3) |
Oil Equivalent (103boe) | |||||
| Proved | ||||||||
| Developed | 72,513 | 0 | 0 | 72,513 | ||||
| Undeveloped | 95,070 | 0 | 0 | 95,070 | ||||
| Total | 167,583 | 0 | 0 | 167,583 | ||||
1. Sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent. 2. CNOOC has represented that the estimates of net proved reserves provided herein are accurate and that totals may vary due to rounding. | ||||||||
In comparing the detailed net proved reserves estimates prepared by DeGolyer and MacNaughton and by CNOOC, differences have been found, both positive and negative, when compared on the basis of net equivalent barrels. It is DeGolyer and MacNaughton’s opinion that the net proved reserves estimates prepared by CNOOC on the properties evaluated and referred to above, when compared on the basis of net equivalent barrels, in aggregate, are reasonable because they reflect a difference of not more than plus or minus 10 percent from those prepared by DeGolyer and MacNaughton.
CNOOC’s
reserves were estimated assuming the continuation of the current regulatory environment. Changes in the regulatory environment by host
governments may affect the operating environment and oil and gas reserves estimates of industry participants. Such regulatory changes
could include increased mandatory government participation in producing contracts, changes in royalty terms, cancellation or
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amendment of contract rights, or expropriation or nationalization of property. While the industry is subject to regulatory changes that could affect an industry participant’s ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2020, estimated reserves.
DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. This report does not constitute a legal or accounting opinion. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in CNOOC or CPG. Our fees were not contingent on the results of our reserves audit. This report has been prepared at the request of CPG on behalf of CNOOC. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.
Submitted,
/s/ DeGolyer and MacNaughton
DeGOLYER and MacNAUGHTON Texas Registered Engineering Firm F-716 |
| /s/ Thomas C. Pence | |
| [SEAL] | Thomas C. Pence, P.E. Senior Vice President |
| DeGolyer and MacNaughton |
| CC: | Mr. Michael Guardia, Sr. Manager – Subsurface Technical, International Development (CNOOC International Limited) |
| Mr. Keith Henderson, VP – International Developments, Global Exploration and International Developments (CNOOC International Limited) | |
| Ms. Cassidy Fuller, Deloitte LLP |
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CERTIFICATE of QUALIFICATION
I, Thomas C. Pence, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:
| 1. | That I am a Senior Vice President of DeGolyer and MacNaughton, which firm did prepare the report of third party dated January 22, 2021, on the proved reserves audit of certain properties attributable to CNOOC Limited, and that I, as Senior Vice President, was responsible for the preparation of this report of third party. |
| 2. | That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in 1982; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers and that I have in excess of 38 years of experience in oil and gas reservoir studies and reserves audits. |
| /s/ Thomas C. Pence | |
| [SEAL] | Thomas C. Pence, P.E. Senior Vice President |
| DeGolyer and MacNaughton |
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| This ‘20-F’ Filing | Date | Other Filings | ||
|---|---|---|---|---|
 | ||||
| Filed on: | 4/22/21 | 6-K | ||
| 1/22/21 | 6-K | |||
| For Period end: | 12/31/20 | |||
| 10/25/20 | ||||
| List all Filings | ||||