Current Report by a Foreign Private Issuer — Form 6-K Filing Table of Contents
Document/ExhibitDescriptionPagesSize
1: 6-K Current Report by a Foreign Private Issuer HTML 11K
2: EX-99.1 Miscellaneous Exhibit HTML 102K
3: EX-99.2 Miscellaneous Exhibit HTML 607K
4: EX-99.3 Miscellaneous Exhibit HTML 470K
Recent Accounting Standards and Changes in Accounting
Policies
9.0
Outstanding Share Data
10.0
Reader Advisories
1.0
Summary of Quarterly Results
Three months ended
Quarterly Summary
Sept. 30
Jun. 30
Mar.
31
Dec. 31
Sept. 30
Jun. 30
Mar. 31
Dec. 31
($ millions, except where indicated)
2018
2018
2018
2017
2017
2017
2017
2016
Production
(mboe/day)
296.7
295.5
300.4
320.4
317.7
319.5
334.0
327.0
Gross
revenues and Marketing and other(1)
6,300
5,983
5,262
5,534
4,713
4,351
4,348
3,865
Net
earnings (loss)
545
448
248
672
136
(93
)
71
186
Per
share – Basic
0.53
0.44
0.24
0.66
0.13
(0.10
)
0.06
0.19
Per
share – Diluted
0.53
0.44
0.24
0.66
0.13
(0.10
)
0.06
0.19
Adjusted
net earnings (loss)(2)
568
474
245
665
136
10
73
(6
)
Funds
from operations(2)
1,318
1,208
895
1,014
891
715
686
662
Per
share – Basic
1.31
1.20
0.89
1.01
0.89
0.71
0.68
0.66
Per
share – Diluted
1.31
1.20
0.89
1.01
0.89
0.71
0.68
0.66
(1)
During the third quarter of 2017, the Company corrected certain intrasegment sales eliminations. Gross revenues and purchases of crude oil and products have been recast for the first two quarters of 2017. There was no impact on net earnings.
(2)
Adjusted net earnings (loss) and funds from operations are non-GAAP measures. The calculation of funds from operations changed in the second quarter of 2017.
Prior periods have been revised to conform to current presentation. Refer to Section 10.3 for a reconciliation to the GAAP measures and an explanation of the changes.
Performance
•
Net earnings of $545 million in the third quarter of 2018 compared to net earnings of $136 million in the third quarter of 2017, with the increase primarily due to:
•
Higher earnings from crude oil marketing activities due to the widening of location pricing differentials between Canada and the U.S., which the Company is able to capture due to its committed capacity on the Keystone pipeline;
•
Higher realized crude oil prices;
•
Higher
natural gas production from Asia Pacific;
•Higher realized margins at the Lloydminster Upgrader; and
•Higher realized U.S. Refining and Marketing margins.
Partially offset by:
•
Lower Upstream production due to the factors described below.
•
Funds from operations of $1,318 million in the
third quarter of 2018 compared to $891 million in the third quarter of 2017, with the increase primarily attributed to the same factors noted above for net earnings.
•
Production decreased by 21.0 mboe/day or 7 percent to 296.7 mboe/day in the third quarter of 2018 compared to the third quarter
of 2017 as a result of:
•
Lower crude oil and natural gas production in Western Canada due to the disposition of select legacy assets in 2017;
•
Lower heavy crude oil production due to natural declines and reduced optimization activities in the Company's non-thermal developments;
•
Lower
crude oil production in Asia Pacific due to the expiry of the Company's participation in Wenchang in the fourth quarter of 2017;
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 1
•
Lower production from Atlantic due to a high water cut well at North Amethyst combined with natural well declines; and
•
Lower
bitumen production from the Tucker Thermal Project and Sunrise Energy Project due to planned turnaround and maintenance.
Partially offset by:
•
Higher natural gas and natural gas liquids (“NGL”) production from the Liwan and BD projects; and
•
Higher NGL production from Western Canada.
2.0 Husky Business Overview
Husky
Energy Inc. (“Husky” or the “Company”) is a Canadian integrated energy company and is based in Calgary, Alberta. The Company’s common shares are listed on the Toronto Stock Exchange (“TSX”) under the symbol “HSE” and the Cumulative Redeemable Preferred Shares Series 1, Series 2, Series 3, Series 5 and Series 7 are listed under the symbols “HSE.PR.A”, “HSE.PR.B”, “HSE.PR.C”, “HSE.PR.E” and “HSE.PR.G”, respectively. The Company operates in Canada, the United States and the Asia Pacific region with Upstream and Downstream business segments.
2.1 Corporate Strategy
The
Company’s business strategy is to focus on returns from investment in a deep portfolio of opportunities that can generate increased funds from operations and free cash flow.
The Company has two main businesses: (i) an integrated Canada-U.S. Upstream and Downstream corridor ( “Integrated Corridor”); and (ii) production located offshore the east coast of Canada ( “Atlantic”) and offshore China and Indonesia ( “Asia Pacific”) (Atlantic and Asia Pacific collectively, “Offshore”).
Integrated Corridor
The Company’s business in the Integrated Corridor includes crude oil, bitumen, natural gas and NGL production from Western Canada, the Lloydminster
upgrading and asphalt refining complex, the Prince George Refinery, Husky Midstream Limited Partnership (35 percent working interest and operatorship), and the Lima, Toledo (50 percent working interest) and Superior refineries in the U.S. midwest. Natural gas production from the Western Canada portfolio is closely aligned with the Company’s energy requirements for refining and thermal bitumen production and acts as a natural hedge.
Offshore
The Company’s Offshore business includes operations, development and exploration in Asia Pacific and Atlantic. Each area generates high-netback production, with near and long-term investment potential.
2.2 Operations
Overview and Q3 Highlights
Upstream Operations
Upstream operations in the Integrated Corridor and Offshore include exploration for, and development and production of, crude oil, bitumen, natural gas and NGL (“Exploration and Production”) and marketing of the Company’s and other producers’ crude oil, natural gas, NGL, sulphur and petroleum coke, pipeline transportation, the blending of crude oil and natural gas and storage of crude oil, diluent and natural gas (“Infrastructure and Marketing”). Infrastructure and Marketing markets and distributes products to customers on behalf of Exploration and Production and is grouped in the Upstream business segment based on the nature of its interconnected operations. The
Company’s Upstream operations are located in Western Canada, Asia Pacific and Atlantic.
Exploration and Production
Thermal Developments
The Company continued to advance its inventory of thermal projects in the third quarter of 2018. These long-life developments are being built with modular, repeatable designs and require low sustaining capital once brought online.
Total bitumen production, including Lloyd thermal bitumen projects, the Tucker Thermal Project and the Sunrise Energy Project, averaged 117,300 bbls/day in the third quarter of 2018.
HUSKY ENERGY INC. |
Q3 | Management's Discussion and Analysis | 2
Lloyd Thermal Bitumen Projects
The Company expects to bring on 60,000 bbls/day of long-life thermal bitumen production through to 2021.
Development continued at the 10,000 bbls/day Rush Lake 2 Thermal Project. Construction of the Central Processing Facility (“CPF”) was completed and first steam was achieved in late July. First production commenced in October 2018, with ramp-up to 10,000 bbls/day design capacity expected by the first quarter of 2019.
At the Dee Valley Thermal Project, drilling
of the second pad was completed in the third quarter of 2018. Construction on the CPF continued and is ahead of schedule with concrete works completed, all modules delivered to site and set, Once-Through Steam Generators (“OTSG”) assembled, with mechanical, electrical, and building construction underway. First oil is now expected in the fourth quarter of 2019, compared to a previous expected timeframe of 2020.
At the Spruce Lake Central Thermal Project, drilling of the first well pad was completed in the third quarter of 2018, and piling for the CPF is underway. First production is expected in 2020.
At the Spruce Lake North Project, site clearing is in progress with production expected in late 2020.
In November 2017, the Company sanctioned two new
10,000 bbls/day thermal projects. First production from these two projects is expected in the second half of 2021.
Tucker Thermal Project
Total production at the Tucker Thermal Project is expected to reach its 30,000 bbls/day design capacity around the end of 2018, previously expected to reach nameplate capacity by the end of 2018. In support of reaching design capacity, a planned turnaround was completed in the third quarter of 2018.
Sunrise Energy Project
Total production averaged 49,400 bbls/day (24,700 bbls/day Husky working interest) during the third quarter of 2018. Production in the quarter was impacted by steam limitations due to OTSG maintenance activity. The project is expected to near nameplate capacity around the end of 2018, previously expected to reach nameplate capacity by the
end of 2018.
Ten infill wells have been drilled in 2018 and are expected to come online in the fourth quarter of 2018.
Western Canada
Oil and Natural Gas Resource Plays
An accelerated drilling program from an 18-well program to a 25-well development program in the Spirit River formation, in the Ansell and Kakwa areas, is underway with 15 wells drilled in 2018, and 13 completed.
A drilling program targeting the oil and liquids-rich gas Montney formation in the Karr and Wembley areas is continuing with four wells drilled in 2018, and three completed.
Non-Thermal Developments
The Company
is managing the natural decline in Cold Heavy Oil Production with Sand operations with an active optimization program as well as using waterflooding, polymer injection technology, and enhanced oil recovery.
Asia Pacific
China
Block 29/26
Construction continues at Liuhua 29-1, the third deepwater gas field of the Liwan Gas Project. All of the major contracts have been executed and detailed design work is underway. Drilling of three additional wells is scheduled to commence in the fourth quarter of 2018, once the Environmental Impact Assessment is approved by the Ministry of Ecology and Environment, which will add to the four previously drilled wells. First gas production from this seven-well development
is expected around the end of 2020, with target net production of 45 mmcf/day natural gas and 1,800 bbls/day NGL when fully ramped up.
The Company holds a working interest of 75 percent in this field development.
Blocks 15/33 and 16/25
The Company is progressing commercial development plans following the successful drilling and testing of an exploration well on Block 15/33.
During the third quarter of 2018, the Company drilled one exploration well at the nearby exploration Block 16/25 which encountered hydrocarbons. Additional evaluation work is
being conducted.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 3
The Company is the operator of both blocks with a working interest of 100 percent during the exploration phase. In the event of a commercial discovery, China National Offshore Oil Corporation Limited (“CNOOC”) may assume a participating partnership interest of up to 51 percent in either or both blocks for the development and production phases.
Blocks 22/11 and 23/07
The
Company and CNOOC signed two Production Sharing Contracts (“PSC”) for Blocks 22/11 and 23/07 in the Beibu Gulf area of the South China Sea in the first half of 2018. The Company is the operator of both blocks with a working interest of 100 percent during the exploration phase. In the event of a commercial discovery, CNOOC may assume a participating partnership interest of up to 51 percent in either or both blocks for the development and production phases.
Indonesia
Madura Strait
During the third quarter of 2018, the BD Project achieved its gross daily sales target and reached average gross natural gas production of 100 mmcf/day (40 mmcf/day Husky working
interest) and gross NGL production of 10,400 bbls/day (4,200 bbls/day Husky working interest).
At the MDA and MBH fields, the two shallow water platforms have been fully installed and preparations are underway to drill the five MDA and two MBH field production wells in 2019, previously expected to be drilled in the second half of 2018. Gas production and sales are expected to start in 2020, previously expected to start in the second half of 2019, following completion of the Floating Production Unit (“FPU”) which will be used to process and compress the gas. An additional shallow water field, named MDK, is scheduled to be developed and tied into the FPU in 2021. The processed gas from these three fields will be tied directly into the East Java subsea pipeline system and sold to the East Java market under long-term contracts with
set prices that include escalation factors.
Atlantic
White Rose Field and Satellite Extensions
Project activity continues to ramp up on the West White Rose Project. Construction of the concrete gravity structure began in the first half of 2018 at the purpose-built graving dock in Argentia, Newfoundland and Labrador. The structure's base slab was completed in mid-September and the first round of slip forming is scheduled for the fourth quarter of 2018. First production is expected in 2022.
The Company continues to progress a subsea program to offset natural reservoir declines through infill drilling and workover operations at the White Rose field and satellite extensions. During the third quarter of 2018, two
well workovers were completed and two additional infill wells are scheduled to come online around the fourth quarter of 2018.
Atlantic Exploration
The Company continued to evaluate the results of a recent discovery at the A-24 exploration well north of the White Rose field and further delineation opportunities in the area are currently being evaluated. The Company has a 68.875 percent ownership interest, with partners Suncor Energy and Nalcor Energy Oil and Gas holding 26.125 percent and five percent, respectively.
Infrastructure and Marketing
Husky Midstream Limited Partnership (“HMLP”)
LLB
Direct – Cold Lake Gathering System to Hardisty
During 2017, HMLP commenced the construction of a new 150-kilometre pipeline system in Alberta, which creates additional pipeline capacity to handle the expected growth in the Company’s thermal operations in Alberta and Saskatchewan. The construction is ahead of schedule and is expected to be completed in the fourth quarter of 2018.
Saskatchewan Gathering System Expansion
A multi-year expansion program is underway and will provide transportation of diluent and heavy oil blend for several additional thermal plants including Rush Lake 2.
Ansell Corser Plant
The new gas processing plant is now under construction and is
expected to add 120 mmcf/day of processing capacity when it comes online in the fourth quarter of 2019.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 4
Downstream Operations
Downstream operations in the Integrated Corridor in Canada include upgrading of heavy crude oil feedstock into synthetic crude oil (“Upgrading”), refining crude oil, marketing of refined petroleum products including gasoline, diesel, ethanol blended fuels, asphalt and ancillary products, and production of ethanol (“Canadian Refined Products”). It also includes
refining of crude oil in the U.S. to produce and market diesel fuels, gasoline, jet fuel and asphalt (“U.S. Refining and Marketing”). Upgrading, Canadian Refined Products and U.S. Refining and Marketing all process and refine natural resources into marketable products and are grouped together as the Downstream business segment due to the similar nature of their products and services.
U.S. Refining and Marketing
Lima Refinery
Crude Oil Flexibility Project
The crude oil flexibility project is expected to be completed by the end of 2019. The Project is designed to allow for the processing of up to 40,000 bbls/day of heavy crude oil feedstock from Western Canada, providing the ability to swing between light and heavy crude oil feedstock.
Better
Together - Proposed Acquisition of MEG Energy Corp.
On October 2, 2018, the Company announced that it has commenced an unsolicited offer to acquire all of the outstanding common shares of MEG Energy Corp. ("MEG"). Under the terms and subject to the conditions of the offer, each MEG shareholder will have the option to choose to receive consideration per MEG share of $11 in cash or 0.485 of a Husky share, subject to maximum aggregate cash consideration of $1 billion and a maximum aggregate number of Husky shares issued of approximately 107 million. The transaction was valued at $6.4 billion at the time of announcement, which includes approximately $3.1 billion of MEG's net debt.
The
Company believes that acquiring MEG will create a combined Canadian energy company that will maintain a strong balance sheet and investment-grade credit ratings and that will increase the Company's free cash flow, funds from operations and production.
The Company has filed applications or notifications for regulatory review and approvals, as applicable, for the transaction under the Investment Canada Act (Canada), Competition Act (Canada), Transportation Act (Canada) and Hart-Scott-Rodino Act.
2.3 Superior Refinery Incident
Operations at the Superior Refinery remain suspended and an investigation
into the cause of the April 26th incident is ongoing. The Company is currently focused on winterizing the site. An engineering contractor has been appointed to oversee design work for the rebuild, with the rebuild beginning once the investigation and design work are complete. Normal operations are not expected to resume until 2020.
As at September 30, 2018, the Company derecognized US$43 million of assets damaged in the incident in the U.S. Refining and Marketing segment. In addition, the Company accrued pre-tax insurance recoveries for property damage, rebuild costs and clean-up costs associated with the incident of US$106 million.
2.4 Financial
Strategic Plan
During the third quarter of 2018:
•
The Board of Directors declared a quarterly dividend of $0.125 per common share, or $126 million, for the second quarter of 2018. The dividends were paid on October 1, 2018, to shareholders of record at the close of business on August 27, 2018; and
•
Dividends
of $9 million were declared on preferred shares in the third quarter of 2018, and were paid on October 1, 2018, to shareholders of record at the close of business on August 27, 2018.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 5
3.0 Business Environment
Average
Benchmarks
Three months ended
Nine months ended
Sept. 30
Jun.
30
Mar. 31
Dec. 31
Sept. 30
Sept. 30
Sept. 30
Average Benchmarks Summary
2018
2018
2018
2017
2017
2018
2017
West
Texas Intermediate (“WTI”) crude oil(1)
(US$/bbl)
69.50
67.88
62.87
55.40
48.21
66.75
49.47
Brent
crude oil(2)
(US$/bbl)
75.23
74.35
66.74
61.39
52.08
72.11
51.91
Light
sweet at Edmonton
($/bbl)
81.92
80.58
72.06
69.02
56.74
78.19
60.88
Western
Canadian Select (“WCS”) at Hardisty(3)
(US$/bbl)
47.25
48.61
38.59
43.14
38.27
44.82
37.59
Lloyd
heavy crude oil at Lloydminster
($/bbl)
54.01
53.15
37.31
47.97
44.05
48.16
43.16
WTI/Lloyd
crude blend differential
(US$/bbl)
22.06
19.08
23.92
12.07
9.59
21.68
11.66
Condensate
at Edmonton
(US$/bbl)
66.65
68.83
63.04
57.97
47.60
66.17
49.43
NYMEX
natural gas(4)
(US$/mmbtu)
2.90
2.80
3.00
2.93
3.00
2.90
3.17
NOVA
Inventory Transfer (“NIT”) natural gas
($/GJ)
1.28
0.97
1.76
1.85
1.93
1.34
2.45
Chicago
Regular Unleaded Gasoline
(US$/bbl)
86.61
84.75
72.96
73.17
66.40
81.55
63.89
Chicago
Ultra-low Sulphur Diesel
(US$/bbl)
92.21
89.14
81.30
80.37
69.69
87.62
65.25
Chicago
3:2:1 crack spread
(US$/bbl)
19.04
18.30
12.84
20.28
19.30
16.78
14.98
U.S./Canadian
dollar exchange rate
(US$)
0.765
0.775
0.791
0.786
0.799
0.777
0.766
Canadian
$ Equivalents(5)
WTI crude oil
($/bbl)
90.85
87.59
79.48
70.48
60.34
85.91
64.58
Brent
crude oil
($/bbl)
98.34
95.94
84.37
78.10
65.18
92.81
67.77
WCS
at Hardisty
($/bbl)
61.76
62.72
48.79
54.89
47.90
57.68
49.07
WTI/Lloyd
crude blend differential
($/bbl)
28.84
24.62
30.24
15.36
12.00
27.90
15.22
NYMEX
natural gas
($/mmbtu)
3.79
3.61
3.79
3.73
3.75
3.73
4.14
(1)
Calendar
Month Average of settled prices for WTI at Cushing, Oklahoma.
(2)
Calendar Month Average of settled prices for Dated Brent.
(3)
WCS is a heavy blended crude oil, comprised of conventional and bitumen crude oils blended with diluent which terminals at Hardisty, Alberta. Quoted prices are indicative of the Index for WCS at Hardisty, Alberta, set in the month prior to delivery.
(4)
Prices
quoted are average settlement prices during the period.
(5)
Prices quoted are calculated using U.S. dollar benchmark commodity prices and monthly average U.S./Canadian dollar exchange rates.
Crude Oil Benchmarks
Global crude oil benchmarks in the third quarter of 2018 increased relative to the third quarter of 2017. WTI averaged US$69.50/bbl during the third quarter of 2018, compared to US$48.21/bbl
during the third quarter of 2017. Brent averaged US$75.23/bbl during the third quarter of 2018, compared to US$52.08/bbl during the third quarter of 2017. WCS averaged US$47.25/bbl during the third quarter of 2018, compared to US$38.27/bbl during the third quarter of 2017.
The price received by the Company for crude oil production from Western Canada is primarily driven by the price of WTI, adjusted to Western Canada.
The price received by the Company for crude oil production from Atlantic and for NGL production from Asia Pacific is primarily driven by the price of Brent. A portion of the Company’s crude oil production from Western Canada is classified as either heavy crude oil or bitumen, which trades at a discount to light crude oil. The Company’s crude oil and NGL production was 72 percent heavy crude oil and bitumen in both the third quarter of 2018 and 2017.
The
Company’s heavy crude oil and bitumen production is blended with diluent (condensate) in order to facilitate its transportation through pipelines. Therefore, the price received for a barrel of blended heavy crude oil or bitumen is impacted by the prevailing market price for condensate. The price of condensate at Edmonton increased in the third quarter of 2018 compared to the third quarter of 2017, primarily due to the increase in light crude oil benchmark pricing.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 6
Natural
Gas Benchmarks
The NIT natural gas price benchmark decreased in the third quarter of 2018 compared to the third quarter of 2017, primarily due to the continued oversupply of natural gas in North America.
The price received by the Company for natural gas production from Western Canada is primarily driven by the NIT near-month contract price of natural gas, while the price received by the Company for production from Asia Pacific is determined by fixed long-term sales contracts.
North American natural gas is consumed internally by the Company’s Upstream and Downstream operations, helping to mitigate the impact of weak natural gas benchmark prices on results.
Refining Benchmarks
The Chicago 3:2:1 crack spread is the key indicator for U.S. refining margins and reflects refinery gasoline output that is approximately twice the distillate output, and is calculated as the price of two-thirds of a barrel of gasoline plus one-third of a barrel of distillate fuel less one barrel of crude oil. Market crack spreads are based on quoted near-month contracts for WTI and spot prices for gasoline and diesel and do not reflect the actual crude purchase costs
or the product configuration of a specific refinery. The Chicago Regular Unleaded Gasoline and the Chicago Ultra-low Sulphur Diesel average benchmark prices are the standard products included in the Chicago 3:2:1 crack spread. The Chicago 3:2:1 crack spread is based on last in first out (“LIFO”) accounting, which is a non-GAAP measure (refer to section 10.3).
The Chicago 3:2:1 crack spread is a gross margin based on the prices of unblended fuels. The cost of purchasing Renewable Identification Numbers (“RINs”) or physically blending biofuel into a final gasoline or diesel product has not been deducted from the Chicago 3:2:1 gross margin. The market value of gasoline or distillate that has been blended may be lower than the value of unblended petroleum products given the value a buyer of unblended petroleum can gain by generating RINs through blending. The
Company sells both blended and unblended fuels with the goal of maximizing margins net of RINs purchases.
The Company’s realized refining margins are affected by the product configuration of its refineries, crude oil feedstock, product slates, transportation costs to benchmark hubs and the time lag between the purchase and delivery of crude oil. The product slates produced at the Lima, BP-Husky Toledo and Superior refineries contain between 14 to 42 percent of other products that are sold at discounted market prices compared to gasoline and distillate. The Company’s realized refining margins are accounted for on a first in first out (“FIFO”) basis in accordance with International Financial Reporting Standards (“IFRS”).
Foreign
Exchange
The majority of the Company’s revenues are received in U.S. dollars from the sale of oil and gas commodities and refined products whose prices are determined by reference to U.S. benchmark prices. The majority of the Company’s non-hydrocarbon related expenditures are denominated in Canadian dollars. An increase in the value of the Canadian dollar relative to the U.S. dollar will decrease the revenues received from the sale of oil and gas commodities. Correspondingly, a decrease in the value of the Canadian dollar relative to the U.S. dollar will increase the revenues received from the sale of oil and gas commodities. In addition, changes in foreign exchange rates impact the translation of U.S. Downstream and Asia Pacific operations and U.S. dollar denominated
debt. The Canadian dollar averaged US$0.765 in the third quarter of 2018 compared to US$0.799 in the third quarter of 2017.
A portion of the Company’s long-term sales contracts in Asia Pacific are priced in Chinese Yuan (“RMB”). An increase in the value of RMB relative to the Canadian dollar will increase the revenues received in Canadian dollars from the sale of natural gas commodities in the region. The Canadian dollar averaged RMB 5.209 in the third
quarter of 2018 compared to RMB 5.325 in the third quarter of 2017.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 7
Sensitivity Analysis
The following table is indicative of the impact of changes in certain key variables in the third quarter of 2018 on earnings before income taxes and net earnings on an annualized basis. The table below reflects what the effect would have
been on the financial results had the indicated variable increased by the notional amount. The analysis is based on business conditions and production volumes during the third quarter of 2018. Each separate item in the sensitivity analysis shows the approximate effect of an increase in that variable only; all other variables are held constant. While these sensitivities are indicative for the period and magnitude of changes on which they are based, they may not be applicable in other periods, under other economic circumstances or upon greater magnitudes of change.
2018
Third
Quarter
Effect on Earnings
Effect on
Sensitivity Analysis
Average
Increase
before
Income Taxes(1)
Net Earnings(1)
($ millions)
($/share)(2)
($
millions)
($/share)(2)
WTI benchmark crude oil price(3)(4)
69.50
US $1.00/bbl
91
0.09
67
0.07
NYMEX
benchmark natural gas price(5)
2.90
US $0.20/mmbtu
—
—
—
—
WTI/Lloyd
crude blend differential(6)
22.06
US $1.00/bbl
—
—
—
—
Canadian
asphalt margins
23.39
Cdn $1.00/bbl
13
0.01
9
0.01
Canadian
light oil margins
0.044
Cdn $0.005/litre
15
0.01
11
0.01
Chicago
3:2:1 crack spread
19.04
US $1.00/bbl
113
0.11
88
0.09
Exchange
rate (US $ per Cdn $)(3)(7)
0.765
US $0.01
(87
)
(0.09
)
(64
)
(0.06
)
(1)
Excludes
mark to market accounting impacts.
(2)
Based on 1,005.1 million common shares outstanding as at September 30, 2018.
(3)
Does not include gains or losses on inventory.
(4)
Includes
impacts related to Brent-based production.
(5)
Includes impact of natural gas consumption by the Company.
(6)
Excludes impact on Canadian asphalt operations.
(7)
Assumes
no foreign exchange gains or losses on U.S. dollar denominated long-term debt and other monetary items, including cash balances.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 8
4.0 Results of Operations
4.1 Upstream
Exploration and Production
Exploration
and Production Earnings Summary
Three months ended September 30,
Nine months ended September 30,
($ millions)
2018
2017
2018
2017
Gross
revenues
1,319
1,157
3,687
3,623
Royalties
(106
)
(71
)
(285
)
(266
)
Net
revenues
1,213
1,086
3,402
3,357
Purchases of crude oil and products
—
—
1
1
Production,
operating and transportation expenses
398
413
1,139
1,260
Selling, general and administrative expenses
71
63
224
181
Depletion,
depreciation, amortization and impairment (“DD&A”)
461
514
1,342
1,766
Exploration and evaluation expenses
26
31
96
108
Loss
(gain) on sale of assets
2
3
(2
)
(29
)
Other – net
(42
)
(7
)
(11
)
(31
)
Share
of equity investment loss (income)
(12
)
1
(33
)
1
Financial items
27
29
68
94
Provisions
for income taxes
68
11
149
2
Net earnings
214
28
429
4
Third
Quarter
Exploration and Production net revenues increased by $127 million in the third quarter of 2018 compared to the third quarter of 2017, primarily due to higher average realized sales prices partially offset by lower production, both of which are described in more detail below.
DD&A expense decreased by $53 million in the third quarter of 2018 compared to the third quarter of 2017, primarily due to lower production and additional heavy oil and bitumen reserve bookings in the fourth quarter of
2017.
Provisions for income taxes increased by $57 million in the third quarter of 2018 compared to the third quarter of 2017, primarily due to higher earnings before income taxes in the third quarter of 2018.
Nine Months
Exploration and Production net revenues increased by $45 million compared to the same period in 2017, primarily due to higher average realized sales prices partially offset by lower production, both of which are described in more detail below.
Production,
operating and transportation expenses decreased by $121 million compared to the same period in 2017, primarily due to lower production and the dispositions of properties with higher unit operating costs in Western Canada.
Selling, general and administrative expenses increased by $43 million compared to the same period in 2017, primarily due to higher employee costs.
DD&A expense decreased by $424 million compared to the same period in 2017, primarily
due to the same factors which impacted the third quarter combined with the recognition of a pre-tax impairment charge of $168 million in the second quarter of 2017.
Gain on sale of assets decreased by $27 million compared to the same period in 2017, primarily due to the disposition of select legacy assets in Western Canada in 2017.
Share of equity investment income increased by $34 million compared to the same period in 2017, primarily due to the investment in the Husky-CNOOC Madura Ltd. joint venture, which is accounted for under the equity method.
The BD Project reached first production in the third quarter of 2017.
Provisions for income taxes increased by $147 million compared to the same period in 2017, primarily due to the same factors which impacted the third quarter.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 9
Average Sales Prices Realized
Three
months ended September 30,
Nine months ended September 30,
Average Sales Prices Realized
2018
2017
2018
2017
Crude
oil and NGL ($/bbl)
Light and Medium crude oil
93.84
63.13
89.04
64.50
NGL(1)
60.08
37.83
56.61
41.18
Heavy
crude oil
50.09
41.89
45.48
41.73
Bitumen
46.00
38.14
39.35
36.93
Total
crude oil and NGL average
56.02
43.62
49.99
44.43
Natural gas average ($/mcf)(1)
6.15
5.25
6.55
5.39
Total
average ($/boe)
50.44
40.05
47.02
41.07
(1)
Reported
average NGL and natural gas prices include Husky’s net working interest from the BD Project (40 percent). Revenues and expenses related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under the equity method for interim financial statement purposes.
Third Quarter
The average sales prices realized by the Company for crude oil and NGL production increased by 28 percent in the third quarter of 2018 compared to the third quarter of 2017, reflecting an increase in commodity benchmark prices.
The average sales prices realized by the
Company for natural gas production increased by 17 percent in the third quarter of 2018 compared to the third quarter of 2017. The increase was primarily due to a higher percentage of fixed priced natural gas production from both the Liwan Gas Project and BD Project relative to total natural gas production.
Nine Months
The average sales prices realized by the Company for crude oil and NGL production increased by 13 percent compared to the same period in 2017,
primarily due to the same the factors which impacted the third quarter.
The average sales prices realized by the Company for natural gas production increased by 22 percent compared to the same period in 2017, primarily due to the same factors which impacted the third quarter.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 10
Daily
Gross Production
Three months ended September 30,
Nine months ended September 30,
Daily Gross Production
2018
2017
2018
2017
Crude
Oil and NGL (mbbls/day)
Western Canada
Light
and Medium crude oil
9.9
11.1
9.4
12.5
NGL
11.9
11.4
11.8
10.1
Heavy
crude oil
34.6
44.1
37.6
45.1
Bitumen(1)
117.3
117.7
121.2
118.5
173.7
184.3
180.0
186.2
Atlantic
White Rose and Satellite Fields – light crude oil
21.0
23.6
20.0
30.7
Terra
Nova – light crude oil
2.8
2.1
4.3
3.7
23.8
25.7
24.3
34.4
Asia
Pacific
Wenchang – light crude oil
—
5.9
—
6.2
Liwan
and Wenchang – NGL(2)
8.4
7.9
8.1
6.8
Madura –NGL(3)
4.2
—
2.3
—
12.6
13.8
10.4
13.0
210.1
223.8
214.7
233.6
Natural
gas (mmcf/day)
Western Canada
297.6
379.5
287.2
390.4
Asia
Pacific
Liwan(2)
181.9
168.6
180.6
145.0
Madura(3)
40.0
15.3
29.2
5.1
221.9
183.9
209.8
150.1
519.5
563.4
497.0
540.5
Total (mboe/day)
296.7
317.7
297.5
323.7
(1)
Bitumen
consists of production from thermal developments in Lloydminster, the Tucker Thermal Project located near Cold Lake, Alberta and the Sunrise Energy Project.
(2)
Reported production volumes include Husky’s working interest production from the Liwan Gas Project (49 percent).
(3)
Reported production volumes include Husky’s working interest from the BD Project (40 percent). Revenues and expenses related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under
the equity method for interim financial statement purposes.
Crude Oil and NGL Production
Third Quarter
Crude oil and NGL production decreased by 13.7 mbbls/day in the third quarter of 2018 compared to the third quarter of 2017, primarily due to lower production in Western Canada as a result of the disposition of select legacy assets in 2017, a reduction of heavy crude oil production due to natural declines and reduced optimization activities in the Company's non-thermal developments, lower crude oil production in Asia Pacific due to the expiry of
the Company's participation in the Wenchang oilfield petroleum contract in late 2017, lower production from Atlantic due to a high water cut well at North Amethyst combined with natural well declines, and lower bitumen production from the Tucker Thermal Project and Sunrise Energy Project due to planned turnaround and maintenance activities. This was partially offset by increased NGL production in Western Canada and Asia Pacific.
Nine Months
Crude oil and NGL production decreased by 18.9 mbbls/day compared to the same period in 2017, primarily due to the same factors which
impacted the third quarter combined with lower production in Atlantic due to a regulatory suspension of production operations on the SeaRose floating production, storage and offloading (“FPSO”) vessel in the first quarter of 2018.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 11
Natural Gas Production
Third Quarter
Natural gas production decreased
by 43.9 mmcf/day in the third quarter of 2018 compared to the third quarter of 2017. In Western Canada, natural gas production decreased by 81.9 mmcf/day, primarily due to the disposition of select legacy assets in 2017. In Asia Pacific, natural gas production increased by 38.0 mmcf/day, primarily due to increased gas demand at the Liwan Gas Project and higher production from the BD Project.
Nine Months
Natural gas production decreased by 43.5 mmcf/day compared
to the same period in 2017, primarily due to the same factors which impacted the third quarter.
2018 Production Guidance
The following table shows actual daily production for the nine months ended September 30, 2018, and the year ended December 31, 2017, as well as updated production guidance for 2018 and the previously issued production guidance for 2018.
Includes Husky’s working interest from the BD Project (40 percent). Revenues and expenses related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under the equity method for interim financial statement purposes.
Annual production
guidance for 2018 has been revised and is now expected to average in the range of 300,000 - 305,000 boe/day. This is due to several factors, including a planned turnaround at the Tucker Thermal Project, planned maintenance at the Sunrise Energy Project, reduced optimization activities in the Company's non-thermal developments, third-party gas and power constraints and lower than anticipated Atlantic production due to well performance.
Royalties
Royalties
Three
months ended September 30,
Nine months ended September 30,
(Percent)
2018
2017
2018
2017
Western
Canada
9
6
9
7
Atlantic
8
6
8
10
Asia
Pacific(1)
7
6
7
6
Total
8
6
8
7
(1)
Reported
royalties include Husky’s working interest from the BD Project (40 percent). Revenues and expenses related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under the equity method for interim financial statement purposes.
Third Quarter
Total royalty rates were eight percent in the third quarter of 2018 compared to six percent in the third quarter of 2017. Royalty rates for Western Canada increased by three percent in the third quarter of 2018 compared to the third quarter
of 2017, primarily due to higher average realized sales prices in 2018 combined with a gas cost allowance credit which reduced the net royalty rate in the third quarter of 2017. Royalty rates for Atlantic increased by two percent in the third quarter of 2018 compared to the third quarter of 2017, primarily due to higher production in the Terra Nova field which has a higher royalty rate.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 12
Nine
Months
In the first nine months of 2018, total royalty rates were eight percent compared to seven percent in the same period in 2017. Royalty rates for Western Canada increased by two percent compared to the same period in 2017, primarily due to the same factors which impacted the third quarter. Royalty rates for Atlantic decreased by two percent compared to the same period in 2017,
primarily due to higher eligible costs partially offset by the same factors which impacted the third quarter.
Operating Costs
Operating Costs
Three months ended September 30,
Nine months ended September 30,
($
millions)
2018
2017
2018
2017
Western Canada
318
336
917
1,020
Atlantic
55
59
156
166
Asia
Pacific(1)
28
23
70
66
Total
401
418
1,143
1,252
Per
unit operating costs ($/boe)
14.68
14.12
14.08
14.17
(1)
Reported
operating costs include Husky’s working interest from the BD Project (40 percent). Revenues and expenses related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under the equity method for interim financial statement purposes.
Third Quarter
Total Exploration and Production operating costs were $401 million in the third quarter of 2018 compared to $418 million in the third quarter of 2017. Total per unit operating costs averaged $14.68/boe in the third quarter of 2018 compared to $14.12/boe in
the third quarter of 2017. The increase in per unit operating costs was primarily due to the factors discussed below.
Per unit operating costs in Western Canada averaged $15.48/boe in the third quarter of 2018 compared to $14.48/boe in the third quarter of 2017. The increase in per unit operating costs was primarily due to a planned turnaround at the Tucker Thermal Project and planned maintenance at the Sunrise Energy Project during the third quarter of 2018.
Per unit operating costs in Atlantic averaged
$25.22/bbl in the third quarter of 2018 compared to $24.98/bbl in the third quarter of 2017. The increase in per unit operating costs was primarily due to lower production in the third quarter of 2018 due to a high water cut well at North Amethyst combined with natural well declines.
Per unit operating costs in Asia Pacific averaged $5.98/boe in the third quarter of 2018 compared to $5.83/boe in the third quarter of 2017.
Nine
Months
In the first nine months of 2018, total Exploration and Production operating costs were $1,143 million compared to $1,252 million in the same period in 2017. Total per unit operating costs averaged $14.08/boe compared to $14.17/boe in the same period in 2017. The decrease in per unit operating costs was primarily due to the factors discussed below.
Per unit operating costs in Western Canada averaged $14.76/boe
compared to $14.87/boe in the same period in 2017. The decrease in per unit operating costs was primarily due to dispositions of properties in Western Canada with higher per unit operating costs partially offset by the same factors which impacted the third quarter.
Per unit operating costs in Atlantic averaged $23.51/bbl compared to $17.68/bbl in the same period in 2017. The increase in per unit operating costs was primarily due to the same factors which impacted the third quarter combined with lower
production due to a regulatory suspension of production operations on the SeaRose FPSO vessel in the first quarter of 2018.
Per unit operating costs in Asia Pacific averaged $5.62/boe compared to $6.40/boe in the same period in 2017. The decrease in per unit operating costs was primarily due to higher production at the Liwan Gas and BD projects.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 13
Exploration
and Evaluation Expenses
Exploration and Evaluation Expenses
Three months ended September 30,
Nine months ended September 30,
($ millions)
2018
2017
2018
2017
Seismic,
geological and geophysical
22
26
70
76
Expensed drilling
1
3
21
22
Expensed
land
3
2
5
10
Total
26
31
96
108
Third Quarter
Exploration and Evaluation expenses in the third quarter of 2018 were $26 million compared to $31 million in the third quarter of 2017. The decrease in seismic, geological and geophysical expense of $4 million, was primarily due to decreased seismic operations in Asia Pacific.
Nine Months
In the first nine months of 2018, Exploration and Evaluation expenses were $96 million,
compared to $108 million in the same period in 2017. The decrease was primarily due to the same factors which impacted the third quarter.
Exploration and Production Capital Expenditures
Exploration and Production capital expenditures were higher in the third quarter of 2018 compared to the third quarter of 2017, reflecting increased spending across the portfolio. Exploration and Production capital expenditures were as follows:
Exploration
and Production Capital Expenditures(1)
Three months ended September 30,
Nine months ended September 30,
($ millions)
2018
2017
2018
2017
Exploration
Western
Canada
32
27
65
47
Thermal developments
—
—
3
1
Atlantic
6
1
65
66
Asia Pacific(2)
18
3
52
6
56
31
185
120
Development
Western
Canada
100
39
226
91
Thermal developments
234
131
577
357
Non-thermal
developments
24
20
54
52
Atlantic
255
134
592
264
Asia
Pacific(2)
45
—
80
—
658
324
1,529
764
Acquisitions
Western
Canada
—
—
4
25
Thermal developments
1
—
40
42
1
—
44
67
Total
715
355
1,758
951
(1)
Excludes
capitalized costs related to asset retirement obligations and capitalized interest incurred during the period.
(2)
Capital expenditures in Asia Pacific exclude amounts related to the Husky-CNOOC Madura Ltd. joint venture, which is accounted for under the equity method for interim financial statement purposes.
Western Canada
In the first nine months of 2018, $295 million (17 percent) was invested in Western Canada, compared to $163 million
(17 percent) in the same period in 2017. Capital expenditures in 2018 related primarily to resource play development targeting the Spirit River formation in the Ansell and Kakwa areas and the Montney formation in the Karr and Wembley areas.
Thermal Developments
In the first nine months of 2018, $620 million (35 percent) was invested in thermal developments compared to $400 million (42 percent) in the same period in 2017. Capital expenditures in 2018
related primarily to the continued development of the Rush Lake 2 Thermal Project, and construction work at the Dee Valley and Spruce Lake Central thermal projects.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 14
Non-Thermal Developments
In the first nine months of 2018, $54 million (three percent) was invested in non-thermal developments compared to $52 million
(five percent) in the same period in 2017. Capital expenditures in 2018 related primarily to sustainment activities.
Atlantic
In the first nine months of 2018, $657 million (37 percent) was invested in Atlantic compared to $330 million (35 percent) in the same period in 2017. Capital expenditures in 2018 related primarily to the development of the West White Rose Project and sustainment and development activities
at the White Rose field and satellite extensions.
Asia Pacific
In the first nine months of 2018, $132 million (eight percent) was invested in Asia Pacific compared to $6 million (one percent) in the same period in 2017. Capital expenditures in 2018 related primarily to the continued development of Liuhua 29-1, and the exploration of Blocks 15/33 and 16/25.
Exploration and Production Wells Drilled
Onshore drilling activity
The
following table discloses the number of wells drilled during the three and nine months ended September 30, 2018 and 2017:
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 15
Infrastructure
and Marketing
Infrastructure and Marketing Earnings Summary
Three months ended September 30,
Nine months ended September 30,
($ millions)
2018
2017
2018
2017
Gross
revenues
601
513
1,681
1,272
Purchases of crude oil and products
567
495
1,590
1,198
Infrastructure
gross margin
34
18
91
74
Marketing and other
168
(4
)
520
31
Total
Infrastructure and Marketing gross margin
202
14
611
105
Production, operating and transportation expenses
2
1
19
6
Selling,
general and administrative expenses
1
1
3
3
Depletion, depreciation, amortization and impairment
—
1
1
2
Loss
on sale of assets
—
—
—
1
Other – net
(1
)
10
1
(2
)
Share
of equity investment income
(6
)
(13
)
(20
)
(61
)
Provisions for income taxes
57
4
166
43
Net
earnings
149
10
441
113
Third Quarter
Infrastructure and Marketing gross revenues and purchases of crude oil and products increased
by $88 million and by $72 million, respectively, in the third quarter of 2018 compared to the third quarter of 2017, primarily due to increased volumes and prices.
Marketing and other increased by $172 million in the third quarter of 2018 compared to the third quarter of 2017, primarily due to crude oil marketing gains from widening location price differentials between Canada and the U.S., which the Company is able to capture due to its committed capacity on the Keystone
pipeline.
Provisions for income taxes increased by $53 million in the third quarter of 2018 compared to the third quarter of 2017, primarily due to higher earnings before income taxes in the third quarter of 2018.
Nine Months
Infrastructure and Marketing gross revenues and purchases of crude oil and products increased by $409 million and by $392 million, respectively, compared to the same period in 2017, primarily
due to the same factors which impacted the third quarter.
Marketing and other increased by $489 million compared to the same period in 2017, primarily due to the same factors which impacted the third quarter.
Share of equity investment income decreased by $41 million compared to the same period in 2017, primarily due to lower revenue and higher maintenance expenses from HMLP in 2018.
Provisions for income taxes increased
by $123 million compared to the same period in 2017, primarily due to the same factors which impacted the third quarter.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 16
4.2 Downstream
Upgrading
Upgrading
Earnings Summary
Three months ended September 30,
Nine months ended September 30,
($ millions, except where indicated)
2018
2017
2018
2017
Gross
revenues
534
377
1,443
988
Purchases of crude oil and products
328
287
818
679
Gross
margin
206
90
625
309
Production, operating and transportation expenses
52
45
144
148
Selling,
general and administrative expenses
2
1
6
6
Depletion, depreciation, amortization and impairment
30
31
87
69
Financial
items
1
1
1
1
Provisions for income taxes
33
3
106
23
Net
earnings
88
9
281
62
Upgrading throughput(mbbls/day)(1)
77.2
76.7
76.9
65.2
Total
sales (mbbls/day)
76.7
79.4
75.1
65.3
Synthetic crude oil sales (mbbls/day)
54.9
58.2
52.6
47.6
Upgrading
differential ($/bbl)
29.46
13.60
29.38
17.73
Unit margin ($/bbl)
29.19
12.32
30.48
17.33
Unit
operating cost ($/bbl)(2)
7.32
6.38
6.86
8.31
(1)
Throughput
includes diluent returned to the field.
(2)
Based on throughput.
Third Quarter
Upgrading gross revenues increased by $157 million in the third quarter of 2018 compared to the third quarter of 2017, primarily due to higher realized prices for synthetic crude oil partially offset by lower sales as a result of increased inventory of Husky Synthetic Blend in response to pipeline apportionment. The price of Husky Synthetic Blend
in the third quarter of 2018 averaged $88.94/bbl compared to $60.43/bbl in the third quarter of 2017.
Upgrading feedstock purchases increased by $41 million in the third quarter of 2018 compared to the third quarter of 2017, primarily due to the increase in the average cost of crude oil feedstock.
Upgrading gross margin increased by $116 million in the third quarter of 2018
compared to the third quarter of 2017, primarily due to the widening of the light/heavy oil differentials. The upgrading differential averaged $29.46/bbl in the third quarter of 2018, an increase of $15.86/bbl or 117 percent, compared to the third quarter of 2017. The differential is equal to Husky Synthetic Blend less Lloyd Heavy Blend.
Provisions for income taxes increased by $30 million in the third quarter of 2018 compared to the third
quarter of 2017, primarily due to higher earnings before income taxes in the third quarter of 2018.
Nine Months
Upgrading gross revenues increased by $455 million compared to the same period in 2017, primarily due to the same factors which impacted the third quarter combined with higher sales volumes as the Lloydminster Upgrader was in a major planned turnaround in the second quarter of 2017. The price of Husky Synthetic Blend averaged $84.16/bbl compared to $64.74/bbl in the same period in 2017.
Upgrading feedstock purchases increased by $139 million compared to the same period in 2017, primarily due to the same factors which impacted the third quarter combined with higher sales as the Lloydminster Upgrader was in a major planned turnaround in the second quarter of 2017.
Upgrading gross margin increased by $316 million compared to the same period in 2017, primarily due to the same factors which impacted the third quarter combined with higher sales volumes as the Lloydminster Upgrader was in a
major planned turnaround in the second quarter of 2017. The upgrading differential averaged $29.38/bbl, an increase of $11.65/bbl or 66 percent compared to the same period in 2017.
Provisions for income taxes increased by $83 million compared to the same period in 2017, primarily due to the same factors which impacted the third quarter.
HUSKY ENERGY INC. |
Q3 | Management's Discussion and Analysis | 17
Canadian Refined Products
Canadian Refined Products Earnings Summary
Three months ended September 30,
Nine
months ended September 30,
($ millions, except where indicated)
2018
2017
2018
2017
Gross
revenues
1,001
802
2,591
1,972
Purchases of crude oil and products
834
650
2,123
1,572
Gross
margin
Fuel
34
35
93
95
Refining
43
28
141
107
Asphalt
76
72
195
155
Ancillary
14
17
39
43
167
152
468
400
Production,
operating and transportation expenses
66
63
198
190
Selling, general and administrative expenses
12
12
36
34
Depletion,
depreciation, amortization and impairment
29
27
86
83
Gain on sale of assets
(2
)
(5
)
(2
)
(5
)
Financial
items
3
3
9
9
Provisions for income taxes
16
14
38
24
Net
earnings
43
38
103
65
Number of fuel outlets(1)
558
557
558
504
Fuel
sales volume, including wholesale
Fuel sales (millions of litres/day)
7.7
8.1
7.5
7.0
Fuel
sales per retail outlet (thousands of litres/day)
12.4
12.4
12.1
11.9
Refinery throughput
Prince
George Refinery (mbbls/day)(2)
11.5
11.9
10.7
11.1
Lloydminster Refinery (mbbls/day)(2)
27.8
30.0
27.8
25.7
Ethanol
production (thousands of litres/day)
772.3
845.9
800.9
798.5
(1)
Average
number of fuel outlets for period indicated.
(2)
Includes all crude oil, feedstock, intermediate feedstock and blend-stocks used in producing sales volumes from the refinery.
Third Quarter
Canadian Refined Products gross revenues increased by $199 million in the third quarter of 2018 compared to the third quarter of 2017, primarily due to higher product prices partially offset by lower fuel sales volumes in the third
quarter of 2018.
Canadian Refined Products purchases of crude oil and products increased by $184 million in the third quarter of 2018 compared to the third quarter of 2017, primarily due to higher commodity prices.
Nine Months
Canadian Refined Products gross revenues increased by $619 million compared to the same period in 2017, primarily due to higher product prices and higher fuel sales volumes from the consolidation of a single expanded truck transport network.
Canadian
Refined Products purchases of crude oil and products increased by $551 million compared to the same period in 2017, primarily due to the same factors which impacted the third quarter combined with higher throughput volumes at the Lloydminster Refinery resulting from a planned turnaround in the second quarter of 2017.
Refining gross margin increased by $34 million compared to the same period in 2017, primarily due to higher product prices.
Asphalt gross margin increased by $40 million
compared to the same period in 2017, primarily due to higher sales prices and higher sales volume at the Lloydminster Refinery resulting from a planned turnaround in the second quarter of 2017.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 18
U.S. Refining and Marketing
U.S.
Refining and Marketing Loss Summary
Three months ended September 30,
Nine months ended September 30,
($ millions, except where indicated)
2018
2017
2018
2017
Gross
revenues
3,198
2,292
9,004
6,600
Purchases of crude oil and products
2,741
1,876
7,811
5,743
Gross
margin
457
416
1,193
857
Production, operating and transportation expenses
222
135
602
412
Selling,
general and administrative expenses
5
4
17
11
Depletion, depreciation, amortization and impairment
Refining
and marketing margin (US$/bbl crude throughput)(2)
17.52
14.98
13.99
10.20
Refinery inventory (mmbbls)(3)
9.5
8.4
9.5
8.4
(1)
Includes
all crude oil, feedstock, intermediate feedstock and blend-stocks used in producing sales volumes from the refinery.
(2)
Prior period has been restated to include impact of U.S. product marketing margin.
(3)
Feedstock and refined products are included in refinery inventory.
Third Quarter
U.S. Refining and Marketing gross revenues increased
by $906 million in the third quarter of 2018 compared to the third quarter of 2017, primarily due to higher refined product prices partially offset by lower sales volumes as the Lima Refinery entered into a major planned turnaround in the third quarter of 2018.
U.S. Refining and Marketing purchases of crude oil and products increased by $865 million in the third quarter of 2018 compared to the third quarter of 2017, primarily due to higher commodity prices partially offset by lower throughput volumes as the Lima Refinery entered into a major planned
turnaround in the third quarter of 2018.
Production, operating and transportation expenses increased by $87 million in the third quarter of 2018 compared to the third quarter of 2017, primarily due to the incident at the Superior Refinery in the second quarter of 2018.
DD&A expense increased by $47 million in the third quarter of 2018 compared to the third quarter of 2017, primarily due to the derecognition of assets damaged during the incident at the
Superior Refinery in the second quarter of 2018.
Other – net increased by $117 million in the third quarter of 2018 compared to the third quarter of 2017, primarily due to insurance recoveries for property damage and recovery costs associated with the incident at the Superior Refinery in the second quarter of 2018.
The Chicago 3:2:1 crack spread is based on LIFO accounting, which assumes that crude oil feedstock costs are based on the current month price of WTI, while crude oil feedstock costs included in realized margins are based on FIFO accounting, which reflects purchases made in previous months. The estimated impact of FIFO accounting was a reduction
in net earnings of approximately $7 million in the third quarter of 2018 compared to an increase in net earnings of approximately $31 million in the third quarter of 2017.
Nine Months
U.S. Refining and Marketing gross revenues increased by $2,404 million, purchases of crude oil and products increased by $2,068 million and production, operating and transportation expenses increased by $190
million compared to the same period in 2017, primarily due to the same factors which impacted the third quarter.
DD&A expense increased by $84 million compared to the same period in 2017, primarily due to the same factors which impacted the third quarter.
Other – net increased by $123 million compared to the same period in 2017, primarily due to the same factors which impacted the third quarter.
HUSKY
ENERGY INC. | Q3 | Management's Discussion and Analysis | 19
Downstream Capital Expenditures
In the first nine months of 2018, Downstream capital expenditures totalled $474 million compared to $469 million in the same period in 2017. In Canada, capital expenditures of $105 million in the first nine months of 2018 related primarily to the scheduled partial turnaround at the Lloydminster
Upgrader in the second quarter of 2018, and various reliability and environmental activities at the Lloydminster and Prince George refineries. In the U.S., capital expenditures of $369 million in the first nine months of 2018 related primarily to the turnaround and crude oil flexibility project at the Lima Refinery, the turnaround at the Superior Refinery, and various reliability and environmental initiatives at the Lima and BP-Husky Toledo refineries.
4.3 Corporate
Corporate
Summary
Three months ended September 30,
Nine months ended September 30,
($ millions) income (expense)
2018
2017
2018
2017
Selling,
general and administrative expenses
(96
)
(61
)
(256
)
(183
)
Depletion, depreciation and amortization
(23
)
(18
)
(65
)
(51
)
Other
– net
—
(12
)
9
(9
)
Net foreign exchange gain (loss)
(9
)
2
16
(11
)
Finance
income
13
9
36
22
Finance expense
(43
)
(58
)
(137
)
(175
)
Recovery
of income taxes
51
75
116
172
Net loss
(107
)
(63
)
(281
)
(235
)
Third
Quarter
The Corporate segment reported a net loss of $107 million in the third quarter of 2018 compared to a net loss of $63 million in the third quarter of 2017. Selling, general and administrative expenses increased by $35 million in the third quarter of 2018, primarily due to the higher stock based compensation expenses.
Nine Months
In the first nine months of 2018,
the Corporate segment reported a net loss of $281 million compared to a net loss of $235 million in the same period in 2017. Selling, general and administrative expenses increased by $73 million compared to the same period in 2017, primarily due to the same factors that impacted the third quarter.
Finance expense decreased by $38 million compared to the same period in 2017,
primarily due to lower interest expense in 2018 from the repayment of long term debt in late 2017.
The net foreign exchange gain increased by $27 million due to items noted below.
Foreign Exchange Summary
Three months ended September 30,
Nine
months ended September 30,
($ millions, except where indicated)
2018
2017
2018
2017
Non-cash
working capital loss
(12
)
(8
)
(12
)
(13
)
Other foreign exchange gain
3
10
28
2
Net
foreign exchange gain (loss)
(9
)
2
16
(11
)
U.S./Canadian dollar exchange rates:
At
beginning of period
US$0.761
US$0.770
US$0.799
US$0.745
At end of period
US$0.774
US$0.799
US$0.774
US$0.799
Included
in the other foreign exchange gain are realized and unrealized gains and losses on working capital and intercompany financing. The foreign exchange gains on these items can vary significantly due to the large volume and timing of transactions through these accounts in the period. The Company manages its exposure to foreign currency fluctuations with the goal of minimizing the impact of foreign exchange gains and losses on the condensed interim consolidated financial statements.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 20
Consolidated
Income Taxes
Consolidated Income Taxes
Three months ended September 30,
Nine months ended September 30,
($ millions)
2018
2017
2018
2017
Provisions
for (recovery of) income taxes
169
24
420
(18
)
Cash income taxes recovered
(70
)
(122
)
(10
)
(35
)
Third
Quarter
Consolidated income taxes were a provision of $169 million in the third quarter of 2018 compared to a provision of $24 million in the third quarter of 2017. The increase in consolidated income taxes was primarily due to the increase in earnings before income taxes in the third quarter of 2018 compared to the third quarter of 2017, which was partially offset by the U.S. tax reform changes enacted in December 2017.
Nine Months
In
the first nine months of 2018, consolidated income taxes were a provision of $420 million, compared to a recovery of $18 million in the same period in 2017. The increase in consolidated income taxes was primarily due to the same factors which impacted the third quarter.
5.0 Risk Management and Financial Risks
5.1 Risk Management
The
Company is exposed to market risks and various operational risks. For a detailed discussion of these risks, see the Company’s Annual Information Form dated March 1, 2018. The Company has processes in place designed to identify the principal risks of the business and has put in place what it believes is appropriate mitigation to manage such risks where possible. The Company’s operational, political, environmental, financial, liquidity and contract and credit risks have not materially changed since December 31,
2017, which were discussed in the Company’s MD&A for the year ended December 31, 2017.
5.2 Financial Risks
The following provides an update on the Company’s commodity price, interest rate and foreign currency risk management.
Commodity Price Risk Management
The Company uses derivative commodity instruments from time to time to manage exposure
to price volatility on a portion of its crude oil and natural gas production, and it also uses firm commitments for the purchase or sale of crude oil and natural gas. These contracts meet the definition of a derivative instrument and have been recorded at their fair value in accounts receivable, inventory, other assets, accounts payable and accrued liabilities and other long-term liabilities. All derivatives are measured at fair value through profit or loss other than non-financial derivative contracts that meet the Company’s own use requirements.
At September 30, 2018,
the Company was party to crude oil purchase and sale derivative contracts to mitigate its exposure to fluctuations in the benchmark price between the time a sales agreement is entered into and the time inventory is delivered. The Company was also party to third party physical natural gas purchase and sale derivative contracts in order to mitigate commodity price fluctuations. Refer to Note 14 of the condensed interim consolidated financial statements.
Foreign Exchange Risk Management
At
September 30, 2018, Cdn $3.5 billion or 65 percent of the Company’s outstanding long-term debt was denominated in U.S. dollars. The U.S. denominated long-term debt, including amounts due within one year, is exposed to changes in the Canadian/U.S. exchange rate. However, it has been designated as a hedge of the Company’s net investment in selected foreign operations with a U.S. dollar functional currency.
For the three and nine months ended September 30,
2018, the Company incurred an unrealized gain of $51 million and an unrealized loss of $94 million, respectively, arising from the translation of the debt, net of tax of $8 million and net of tax recovery of $15 million, respectively, which was recorded in hedge of net investment within other comprehensive income (loss).
HUSKY ENERGY INC. | Q3 | Management's Discussion
and Analysis | 21
Interest Rate Risk Management
The Company is exposed to fluctuations in short term interest rates as Husky maintains a portion of its debt capacity in revolving and floating rate bank facilities and commercial paper and invests surplus cash in short term debt instruments and money market instruments. The Company is also exposed to interest rate risk when fixed rate debt instruments are maturing and require refinancing or when new debt capital needs to be raised.
By maintaining a mix of both
fixed and floating rate debt, the Company mitigates some of its exposure to interest rate changes. The optimal mix maintained will depend on market conditions. The Company may also enter into interest rate swaps as an additional means of managing current and future interest rate risk.
6.0 Liquidity and Capital Resources
6.1 Sources of Liquidity
Liquidity describes a company’s ability to access cash. Sources of liquidity include funds from operations, proceeds from the issuance of equity,
proceeds from the issuance of short and long-term debt, availability of short and long-term credit facilities and proceeds from asset sales. Since the Company operates in the upstream oil and gas industry, it requires significant cash to fund capital programs necessary to maintain or increase production, develop reserves, acquire strategic oil and gas assets and repay maturing debt.
During times of low oil and gas prices, a portion of capital programs can generally be deferred. However, due to the long cycle times and the importance to future cash flow in maintaining the Company’s production, it may be necessary to utilize alternative sources of capital to continue the Company’s
strategic investment plan during periods of low commodity prices. As a result, the Company frequently evaluates the options available with respect to sources of short and long-term capital resources. The Company believes that it has sufficient liquidity to sustain its operations, fund capital programs and meet non-cancellable contractual obligations and commitments in the short and long-term principally by cash generated from operating activities, cash on hand, the issuance of equity, the issuance of debt, borrowings under committed and uncommitted credit facilities and cash proceeds from asset sales. The Company is continually examining its options with respect to sources of long and short-term capital resources to ensure
it retains financial flexibility.
Commercial paper outstanding is supported by the Company’s syndicated credit facilities.
At September 30, 2018, the Company had $4,276 million of unused credit facilities of which $3,800 million are long-term committed credit facilities and $476 million
are short-term uncommitted credit facilities. A total of $424 million short-term uncommitted borrowing credit facilities was used in support of outstanding letters of credit and $200 million of long-term committed borrowing credit facilities was used in support of commercial paper. At September 30, 2018, the Company had no direct borrowing against committed credit facilities. The maturity dates for the Company's revolving syndicated credit facilities are March 9, 2020 and June
19, 2022, respectively. The Company’s ability to renew existing bank credit facilities and raise new debt is dependent upon maintaining an investment grade credit rating and the condition of capital and credit markets. Credit ratings may be affected by the Company’s level of debt, from time to time.
The Company’s share capital is not subject to external restrictions. The Company's leverage covenant under both of its revolving syndicated credit facilities is debt to capital and calculated as total debt (long-term debt including long-term debt due within one year and short-term
debt) and certain adjusting items specified in the agreement divided by total debt, shareholders’ equity and certain adjusting items specified in the agreement. This covenant is used to assess the Company's financial strength. If the Company does not comply with the covenants under the syndicated credit facilities, there is the risk that repayment could be accelerated. The Company was in compliance with the syndicated credit facility covenants at September 30, 2018, and assessed the risk of non-compliance to be low.
Working capital is the amount by which current
assets exceed current liabilities. At September 30, 2018, working capital was $2,445 million compared to $2,109 million at December 31, 2017.
Sunrise Oil Sands Partnership has an unsecured demand credit facility of $10 million available for general purposes. The Company’s proportionate share is $5 million. There were no amounts drawn on this demand credit facility at September 30, 2018.
HUSKY
ENERGY INC. | Q3 | Management's Discussion and Analysis | 22
On March 30, 2017, the Company filed a universal short form base shelf prospectus (the “2017 Canadian Shelf Prospectus”) with applicable securities regulators in each of the provinces of Canada that enables the Company to offer up to $3.0 billion of common shares, preferred shares, debt securities, subscription receipts, warrants and other units in Canada up to and including April 30, 2019.
The 2017 Canadian Shelf Prospectus replaced the Company's Canadian universal short form base shelf prospectus which expired on March 23, 2017. During the 25-month period that the 2017 Canadian Shelf Prospectus is in effect, securities may be offered in amounts, at prices and on terms set forth in a prospectus supplement.
On January 29, 2018, the Company filed a universal short form base shelf prospectus (“the 2018 U.S. Shelf Prospectus”) with the Alberta Securities Commission. On January 30, 2018, the Company’s related U.S.
registration statement filed with the SEC containing the 2018 U.S. Shelf Prospectus became effective which enables the Company to offer up to US$3.0 billion of debt securities, common shares, preferred shares, subscription receipts, warrants and units of the Company in the U.S. up to and including February 29, 2020. The 2018 U.S. Shelf Prospectus replaced the Company's U.S universal short form base shelf prospectus which expired on January 22, 2018. During the 25-month period that the 2018 U.S. Shelf Prospectus and the related U.S registration statement are effective, securities may be offered in amounts, at prices and on terms
set forth in a prospectus supplement.
As at September 30, 2018, the Company has $3.0 billion in unused capacity under the 2017 Canadian Shelf Prospectus and US$3.0 billion in unused capacity under the 2018 U.S. Shelf Prospectus and related U.S. registration statement. The ability of the Company to utilize the capacity under the 2017 Canadian Shelf Prospectus and 2018 U.S. Shelf Prospectus and related U.S. registration statement is subject to market conditions at the time of sale.
Total debt is defined as long-term debt including long-term debt due within one year and short-term debt.
The Company considers its capital structure to include shareholders’ equity and debt which totalled $24.7 billion as at September 30, 2018 (December
31, 2017 – $23.4 billion). To maintain or adjust the capital structure, the Company may, from time to time, sell assets, issue shares, raise debt and/or adjust its capital spending to manage its current and projected debt levels.
The Company monitors its capital structure and financing requirements using, among other things, non-GAAP financial metrics consisting of debt to capital employed and debt to funds from operations (refer to Section 10.3). The Company’s objective is to maintain a debt to capital employed target of less than 25 percent and a debt to funds from operations ratio
of less than 2.0 times. At September 30, 2018, debt to capital employed was 22.5 percent (December 31, 2017 – 23.2 percent) and debt to funds from operations was 1.3 times (December 31, 2017 – 1.6 times), within the Company’s targets.
To facilitate the management of these ratios, the Company
prepares annual budgets, which are updated depending on varying factors such as general market conditions and successful capital deployment. The annual budget is approved by the Board of Directors.
6.3 Contractual Obligations, Commitments and Off-Balance Sheet Arrangements
Contractual Obligations and Other Commercial Commitments
In the normal course of business, the Company is obligated to make future payments. These obligations represent contracts and other commitments that are known and non-cancellable. Refer to the
Company’s MD&A for the year ended December 31, 2017 under the caption “Liquidity and Capital Resources” which summarizes contractual obligations and commercial commitments as at December 31, 2017. During the three months ended September 30, 2018, there were no material changes to the Company's contractual obligations or non-cancellable commitments.
Off-Balance Sheet Arrangements
The
Company does not believe it has any guarantees or off-balance sheet arrangements that have, or are reasonably likely to have, a current or future effect on the Company’s financial condition, results of operations, liquidity or capital expenditures.
Standby Letters of Credit
On occasion, the Company issues letters of credit in connection with transactions in which the counterparty requires such security.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 23
6.4 Transactions
with Related Parties
The Company performs management services as the operator of the assets held by HMLP for which it earns a management fee. The Company is also the contractor for HMLP and constructs its assets on a cost recovery basis with certain restrictions. HMLP charges an access fee to the Company for the use of its pipeline systems in performing the Company’s blending business, and the Company also pays for transportation and storage services. These transactions are related party transactions, as the
Company has a 35 percent ownership interest in HMLP and the remaining ownership interests in HMLP belong to Power Assets Holdings Limited and CK Infrastructure Holdings Limited, which are affiliates of one of the Company’s principal shareholders. For the three and nine months ended September 30, 2018, the Company charged HMLP $103 million and $284 million, respectively, related to construction and management services. For the three and nine months ended September 30,
2018, the Company had purchases from HMLP of $51 million and $151 million, respectively, related to the use of the pipeline for the Company’s blending, transportation and storage activities. As at September 30, 2018, the Company had $80 million due from HMLP.
7.0 Critical Accounting Estimates and Key Judgments
The
application of some of the Company’s accounting policies requires subjective judgment about uncertain circumstances. The potential effects of these estimates, as described in the Company’s MD&A for the year ended December 31, 2017, as well as critical areas of judgment have not changed during the current period. The emergence of new information and changed circumstances may result in changes to actual results or changes to estimated amounts that differ materially from current estimates.
8.0 Recent Accounting Standards and Changes in Accounting Policies
Recent
Accounting Standards
The Company has not early adopted any standard, interpretation or amendment that has been issued but is not yet effective.
Leases
In January 2016, the IASB issued IFRS 16 Leases, which replaces the current IFRS guidance on leases. Under the current guidance, lessees are required to determine if the lease is a finance or operating lease, based on specified criteria. Finance leases are recognized on the balance sheet while operating leases are recognized in the Consolidated Statements of Income when the expense is incurred. Under IFRS 16, lessees must recognize a lease liability and a right-of-use asset for virtually all lease contracts. The recognition
of the present value of minimum lease payments for certain contracts currently classified as operating leases will result in increases to assets, liabilities, depletion, depreciation and amortization, and finance expense, and a decrease to production, operating and transportation expense upon implementation. An optional exemption to not recognize certain short-term leases and leases of low value can be applied by lessees. For lessors, the accounting remains essentially unchanged. The standard will be effective for annual periods beginning on or after January 1, 2019. Early adoption is permitted, provided IFRS 15 Revenue from Contracts with Customers, has been applied, or is applied at the same date as IFRS 16.
The
implementation of IFRS 16 consists of four phases:
•
Project awareness and engagement – This phase includes identifying and engaging the appropriate members of the finance and operations teams, as well as communicating the key requirements of IFRS 16 to stakeholders, and creating a project steering committee.
•
Scoping – This phase focuses on identifying and categorizing the
Company’s contracts, performing a high-level impact assessment and determining the adoption approach and which optional recognition exemptions will be applied by the Company. This phase also includes identifying the systems impacted by the new accounting standard and evaluating potential system solutions.
•
Detailed analysis and solution development – This phase includes assessing which agreements contain leases and determining the expected conversion differences for leases currently accounted for as operating leases under the existing standard.
This phase also includes selection of the system solution.
•
Implementation – This phase includes implementing the changes required for compliance with IFRS 16. The focus of this phase is the approval and implementation of any new accounting and tax policies, processes, systems and controls, as required, as well as the execution of customized training programs and preparation of disclosures under IFRS 16.
The Company is currently in the implementation phase of implementing IFRS 16. The impact on the
Company’s consolidated financial statements upon adoption of IFRS 16 is currently being assessed, but is expected to be material. The Company is adopting the transition to IFRS 16 using the modified retrospective approach.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 24
In
September 2015, the IASB published an amendment to IFRS 15 Revenue from Contracts with Customers, deferring the effective date to annual periods beginning on or after January 1, 2018. IFRS 15 replaces existing revenue recognition guidance with a single comprehensive accounting model. The standard requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive when control is transferred to the purchaser. The Company retrospectively adopted the standard on January 1, 2018. The adoption of IFRS 15 did not require any material adjustments to the amounts recorded in the consolidated financial statements; however, additional disclosures are presented
in the interim consolidated financial statements.
Revenue is recognized when the performance obligations are satisfied and revenue can be reliably measured. Revenue is measured at the consideration specified in the contracts and represents amounts receivable for goods or services provided in the normal course of business, net of discounts, customs duties and sales taxes. Natural gas sales in the Asia Pacific region are under long term, fixed price contracts. Substantially all other revenue is based on floating prices. Performance obligations associated with the sale of crude oil, crude oil equivalents, and refined products are satisfied at the point in time when the products are delivered to and title passes to the customer.
Performance obligations associated with processing services, transportation, blending and storage, and marketing services are satisfied at the point in time when the services are provided.
Financial Instruments
In July 2014, the IASB issued IFRS 9 Financial Instruments to replace IAS 39, which provides a single model for classification and measurement based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial instruments. For financial liabilities, the change in fair value resulting from an entity’s own credit risk is recorded in other comprehensive income rather than net earnings, unless this creates an accounting mismatch. IFRS 9 includes a new, forward-looking ‘expected loss’ impairment model that will result in a more timely recognition of expected credit losses. In addition, IFRS
9 provides a substantially-reformed approach to hedge accounting. The standard was effective for annual periods beginning on January 1, 2018. The Company retrospectively adopted the standard on January 1, 2018. The adoption of IFRS 9 did not require any material adjustments to the consolidated financial statements.
Financial assets previously classified as loans and receivables (cash and cash equivalents, accounts receivable, restricted cash, and long-term receivables), as well as financial liabilities previously classified as other financial liabilities (accounts payable and accrued liabilities, short-term debt, and long-term debt) have been reclassified to amortized cost. The carrying value and measurement of all financial
instruments remains unchanged. The Company’s current process for assessing short-term receivables lifetime expected credit losses collectively in groups that share similar credit risk characteristics is unadjusted with the adoption of the new impairment model and resulted in no additional impairment allowance. Additionally, long-term receivables were assessed individually under the expected credit loss model and no impairment was concluded.
Amendments to IFRS 2 Share-based payment
In June 2016, the IASB issued amendments to IFRS 2 to be applied prospectively for annual periods beginning on or after January 1, 2018. The amendments clarify how to account for certain types of share-based payment arrangements. The adoption of the amendments did not have
a material impact on the Company’s consolidated financial statements.
cumulative redeemable preferred shares, series 1 10,435,932
•
cumulative redeemable preferred shares, series 2 1,564,068
•
cumulative
redeemable preferred shares, series 3 10,000,000
•
cumulative redeemable preferred shares, series 5 8,000,000
•
cumulative redeemable preferred shares, series 7 6,000,000
•
stock options 19,871,753
•
stock
options exercisable 10,524,588
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 25
10.0 Reader Advisories
10.1 Forward-Looking Statements
Certain statements in this document are forward-looking statements and information (collectively, “forward-looking statements”), within the meaning of the applicable Canadian securities legislation, Section 21E of the United States
Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended. The forward-looking statements contained in this document are forward-looking and not historical facts.
Some of the forward-looking statements may be identified by statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as “will likely result”, “are expected to”, “will continue”, “is anticipated”, “is targeting”, “is estimated”, “intend”, “plan”, “projection”, “could”, “aim”, “vision”, “goals”, “objective”, “target”, “schedules” and “outlook”). In particular, forward-looking statements in this document include, but are not limited to, references
to:
•
with respect to the business, operations and results of the Company generally: the Company’s general strategic plans and growth strategies; the Company’s 2018 production guidance, including guidance for specified areas and product types; expected strategic, financial and operational benefits that may result from a transaction with MEG; and the Company’s objective of maintaining stated debt to capital employed and debt to funds
from operations ratio targets;
•
with respect to the Company's thermal developments: long-life thermal bitumen production expectations through to 2021; the expected timing of ramp-up to capacity at the Rush Lake 2 thermal development; the expected timing of first production at Dee Valley, Spruce Lake North and Spruce Lake Central; the expected timing of first production from, and design capacity of, two new Lloyd thermal projects; total production expectations for 2018, and the expected timing at the Tucker Thermal Project; and the expected timing to reach nameplate capacity, and timing for infill wells to come online, at the Sunrise Energy Project;
•
with
respect to the Company's Western Canada resource plays, 2018 drilling plans in the Ansell, Kakwa, Karr and Wembley areas;
•
with respect to the Company's Offshore business in Asia Pacific: the expected timing of first gas production, and drilling of new wells, at Liuhua 29-1; target net production at Liuhua 29-1 when fully ramped up; drilling plans at Block 16/25 offshore China; the expected timing of drilling of five MDA field production wells and two MBH field production wells, and the expected timing of first gas therefrom; and the expected timing of tie-in of, and production
from, the additional MDK shallow water field;
•
with respect to the Company's Offshore business in Atlantic: the expected timing of the first round of slip forming, and first production, at the West White Rose Project; planned subsea program at the White Rose Field and satellite extensions and expected peak production therefrom; timing for infill wells to come online at White Rose; and evaluation of opportunities for further delineation in the area of the White Rose A-24 exploration well;
•
with
respect to the Company’s Infrastructure and Marketing business: the expected timing of completion of construction of HMLP’s new 150-kilometre pipeline system; and the expected timing the Ansell Corser Plant will come online and expected process capacity of such plant; and
•
with respect to the Company's Downstream operating segment: the expected timing of completion of the crude oil flexibility project at the Lima Refinery; and the expected timing of resumption of normal operations at the Superior Refinery.
There are
numerous uncertainties inherent in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary from production estimates.
Although the Company believes that the expectations reflected by the forward-looking statements presented in this document are reasonable, the Company’s forward-looking statements have been based on assumptions and factors concerning future events that may prove to be inaccurate, including the timing of regulatory approvals, and in respect of a possible transaction with MEG, the ability to meet closing conditions and the ability to integrate the Company’s and MEG’s businesses
and operations and realize financial, operational and other synergies from the proposed transaction. Those assumptions and factors are based on information currently available to the Company about itself (and in respect of a possible transaction with MEG, MEG) and the businesses in which they operate, as applicable. Information used in developing forward-looking statements has been acquired from various sources, including third party consultants, suppliers and regulators, among others.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 26
Because
actual results or outcomes could differ materially from those expressed in any forward-looking statements, investors should not place undue reliance on any such forward-looking statements. By their nature, forward-looking statements involve numerous assumptions, inherent risks and uncertainties, both general and specific, which contribute to the possibility that the predicted outcomes will not occur. Some of these risks, uncertainties and other factors are similar to those faced by other oil and gas companies and some are unique to the Company.
The Company’s Annual Information Form for the year ended December 31, 2017, offer documents (in respect of the offer to acquire MEG) and other documents filed with securities
regulatory authorities (accessible through the SEDAR websitewww.sedar.com and the EDGAR websitewww.sec.gov) describe risks, material assumptions and other factors that could influence actual results and are incorporated herein by reference.
New factors emerge from time to time and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on the Company’s business
or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company's course of action would depend upon management’s assessment of the future considering all information available to it at the relevant time. Any forward-looking statement speaks only as of the date on which such statement is made and, except as required by applicable securities laws, the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated
events.
10.2 Cautionary Note Required by National Instrument 51-101
Unless otherwise noted, historical production volumes provided represent the Company’s working interest share before royalties.
The Company uses the term “barrels of oil equivalent” ( or “boe”), which is consistent with other oil and gas companies’ disclosures, and is calculated on an energy equivalence basis applicable at the burner tip whereby one barrel of crude oil is equivalent to six thousand cubic feet of natural gas. The term boe is used to express the sum of the total company products in one unit that can be used for comparisons. Readers are cautioned that the term boe may be
misleading, particularly if used in isolation. This measure is used for consistency with other oil and gas companies but does not represent value equivalency at the wellhead.
10.3 Non-GAAP Measures
Disclosure of non-GAAP Measures
The Company uses measures primarily based on IFRS and also uses some secondary non-GAAP measures. The non-GAAP measures included in this MD&A and related disclosures are: adjusted net earnings (loss), funds from operations, net debt, debt to capital employed, debt to funds from operations and LIFO. None of these measures are used to enhance the Company’s reported financial performance or position. There are no comparable measures in accordance
with IFRS for debt to capital employed or debt to funds from operations. These are useful complementary measures in assessing the Company’s financial performance, efficiency and liquidity. The non-GAAP measures do not have a standardized meaning prescribed by IFRS and therefore are unlikely to be comparable to similar measures presented by other issuers. They are common in the reports of other companies but may differ by definition and application. All non-GAAP measures used in this MD&A and related disclosures are defined below.
Adjusted Net Earnings (Loss)
Adjusted net earnings (loss) is a non-GAAP measure which should not be considered an alternative to, or more meaningful than, “net earnings (loss)” as determined in accordance with IFRS, as an indicator of financial performance. Adjusted
net earnings (loss) is comprised of net earnings (loss) and excludes items such as after-tax property, plant and equipment impairment charges (reversals), goodwill impairment charges, exploration and evaluation asset write-downs, inventory write-downs and loss (gain) on sale of assets which are not considered to be indicative of the Company’s ongoing financial performance. Adjusted net earnings (loss) is a complementary measure used in assessing the Company’s financial performance through providing comparability between periods.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 27
The
following table shows the reconciliation of net earnings (loss) to adjusted net earnings (loss) for the three months ended:
Adjusted Net Earnings (Loss)
Three months ended
Sept. 30
Jun.
30
Mar. 31
Dec. 31
Sept. 30
Jun. 30
Mar. 31
Dec. 31
($
millions)
2018
2018
2018
2017
2017
2017
2017
2016
Net
earnings (loss)
545
448
248
672
136
(93
)
71
186
Impairment
(impairment reversal) of property, plant and equipment, net of tax
23
21
—
3
—
123
—
(202
)
Exploration
and evaluation asset write-downs, net of tax
—
5
—
—
1
3
—
41
Inventory
write-downs, net of tax
—
—
—
—
—
—
—
6
Loss
(gain) on sale of assets, net of tax
—
—
(3
)
(10
)
(1
)
(23
)
2
(37
)
Adjusted
net earnings (loss)
568
474
245
665
136
10
73
(6
)
Debt
to Capital Employed
Debt to capital employed percentage is a non-GAAP measure and is equal to long-term debt, long-term debt due within one year, and short-term debt divided by capital employed. Capital employed is equal to long-term debt, long-term debt due within one year, short-term debt and shareholders’ equity. Management believes this measure assists management and investors in evaluating the Company’s financial strength.
Debt to Funds from Operations
Debt to funds from operations is a non-GAAP measure and is equal to long-term debt, long-term debt due within one year and short-term debt divided by funds from operations. Funds from operations is equal to cash
flow – operating activities plus change in non-cash working capital. Management believes this measure assists management and investors in evaluating the Company’s financial strength.
The following table shows the reconciliation of debt to funds from operations for the periods ended September 30, 2018, and December 31, 2017:
Funds from operations is a non-GAAP measure which should not be considered an alternative to, or more meaningful than, “cash flow – operating activities” as determined in accordance with IFRS, as an indicator of financial performance. Funds from operations is presented to assist management and investors in analyzing operating performance of the Company in the stated period. Funds from operations equals cash flow – operating activities plus change in non-cash working capital.
Funds from operations was restated in the second quarter of 2017 in order to be more comparable to similar
non-GAAP measures presented by other companies. Changes from prior period presentation include the removal of adjustments for settlement of asset retirement obligations and deferred revenue. Prior periods have been restated to conform to current presentation.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 28
The following table shows the reconciliation of net earnings (loss) to funds from operations and related per share amounts for the periods ended:
Funds
from Operations
Three months ended
Sept. 30
Jun. 30
Mar. 31
Dec. 31
Sept. 30
Jun. 30
Mar.
31
Dec. 31
($ millions)
2018
2018
2018
2017
2017
2017
2017
2016
Net
earnings (loss)
545
448
248
672
136
(93
)
71
186
Items
not affecting cash:
Accretion
23
25
24
28
27
29
28
30
Depletion,
depreciation, amortization and impairment
672
639
618
647
673
862
700
405
Inventory
write-down to net realizable value
—
—
—
—
—
—
—
9
Exploration
and evaluation expenses
—
7
—
—
1
4
1
56
Deferred
income taxes
156
138
77
(360
)
52
(57
)
6
45
Foreign
exchange loss (gain)
(6
)
(2
)
1
1
(3
)
15
(17
)
(29
)
Stock-based
compensation
40
33
21
25
11
8
1
3
Loss
(gain) on sale of assets
—
—
(4
)
(13
)
(2
)
(33
)
2
(52
)
Unrealized
mark to market loss (gain)
(22
)
(26
)
(86
)
57
31
18
(50
)
26
Share
of equity investment income
(18
)
(26
)
(9
)
(1
)
(12
)
(23
)
(25
)
(38
)
Other
(2
)
19
2
8
9
5
(6
)
29
Settlement
of asset retirement obligations
(45
)
(22
)
(49
)
(45
)
(23
)
(20
)
(48
)
(31
)
Deferred
revenue
(25
)
(25
)
(20
)
(5
)
(9
)
—
(2
)
23
Distribution
from joint ventures
—
—
72
—
—
—
25
—
Change
in non-cash working capital
(35
)
(199
)
(366
)
337
3
98
(40
)
(18
)
Cash
flow – operating activities
1,283
1,009
529
1,351
894
813
646
644
Change
in non-cash working capital
35
199
366
(337
)
(3
)
(98
)
40
18
Funds
from operations
1,318
1,208
895
1,014
891
715
686
662
Funds
from operations – basic
1.31
1.20
0.89
1.01
0.89
0.71
0.68
0.66
Funds
from operations – diluted
1.31
1.20
0.89
1.01
0.89
0.71
0.68
0.66
LIFO
The Chicago 3:2:1 market crack spread benchmark is based on LIFO inventory costing, a non-GAAP measure, which assumes that crude oil feedstock costs are based on the current month price of WTI, while on a FIFO basis, the comparable GAAP measure, crude oil feedstock costs included in realized margins reflect purchases made in previous months. Management believes that comparisons between LIFO and FIFO inventory costing assist management and investors in assessing differences in the Company's realized refining margins compared to the Chicago 3:2:1 market crack spread benchmark.
Net Debt
Net debt is a non-GAAP measure that equals total debt less cash and cash equivalents. Total debt is calculated as long-term debt, long-term debt due within one year and short-term
debt. Management believes this measurement assists management and investors in evaluating the Company’s financial strength.
10.4 Additional Reader Advisories
This MD&A should be read in conjunction with the condensed interim consolidated financial statements and related notes.
Readers are encouraged to refer to the Company’s MD&A for the year ended December 31, 2017, the 2017 consolidated financial statements, the Annual Information Form dated March 1, 2018 filed with
Canadian securities regulatory authorities and the 2017 Form 40-F filed with the U.S. Securities and Exchange Commission for additional information relating to the Company. These documents are available at www.sedar.com, at www.sec.gov and at www.huskyenergy.com.
Use of Pronouns and Other Terms Denoting Husky
In this MD&A, the terms “Husky” and the “Company” denote
the corporate entity Husky Energy Inc. and its subsidiaries on a consolidated basis.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 29
Standard Comparisons in this Document
Unless otherwise indicated, the discussions in this MD&A with respect to results for the three months ended September 30, 2018 and the nine months ended September
30, 2018 are compared to the results for the three months ended September 30, 2017 and the nine months ended September 30, 2017. Discussions with respect to the Company’s financial position as at September 30, 2018 are compared to its financial position as at December 31, 2017. Amounts presented within this MD&A are unaudited.
Additional Reader Guidance
•
The
condensed interim consolidated financial statements and comparative financial information included in this MD&A have been prepared in accordance with IAS 34, “Interim Financial Reporting” as issued by the IASB.
•
All dollar amounts are in Canadian dollars, unless otherwise indicated.
•
Unless otherwise indicated, all production volumes quoted are gross, which represent the Company’s working interest share before royalties.
•
Prices
are presented before the effect of hedging.
•
There have been no changes to the Company’s internal controls over financial reporting (“ICFR”) for the three months ended September 30, 2018 that have materially affected, or are reasonably likely to affect, the Company’s ICFR.
Terms
Adjusted
Net Earnings (Loss)
Net earnings (loss) before after-tax property, plant and equipment impairment charges (reversals), goodwill impairment charges, exploration and evaluation asset write-downs, inventory write-downs and loss (gain) on the sale of assets
Asia Pacific
Includes Upstream oil and gas exploration and production activities located offshore China and Indonesia
Atlantic
Includes Upstream oil and gas exploration and production activities
located offshore Newfoundland and Labrador
Bitumen
A naturally occurring solid or semi-solid hydrocarbon consisting mainly of heavier hydrocarbons, with a viscosity greater than 10,000 millipascal-seconds or 10,000 centipoise measured at the hydrocarbon’s original temperature in the reservoir and at atmospheric pressure on a gas-free basis, and that is not primarily recoverable at economic rates through a well without the implementation of enhanced recovery methods
Capital Employed
Long-term debt, long-term debt due within one year, short-term debt and shareholders’ equity
Capital
Expenditures
Includes capitalized administrative expenses but does not include asset retirement obligations or capitalized interest
Capital Program
Capital expenditures not including capitalized administrative expenses or capitalized interest
Debt to Capital Employed
Long-term debt, long-term debt due within one year and short-term debt divided by capital employed
Debt
to Funds from Operations
Long-term debt, long-term debt due within one year and short-term debt divided by funds from operations
Diluent
A lighter gravity liquid hydrocarbon, usually condensate or synthetic oil, added to heavy oil and bitumen to facilitate transmissibility of the oil through a pipeline
Feedstock
Raw materials which are processed into petroleum products
Funds
from Operations
Cash flow – operating activities plus change in non-cash working capital
Gross/Net Acres/Wells
Gross refers to the total number of acres/wells in which a working interest is owned. Net refers to the sum of the fractional working interests owned by a company
Gross Reserves/Production
A company’s working interest share of reserves/production before deduction of royalties
Heavy
crude oil
Crude oil with a relative density greater than 10 degrees API gravity and less than or equal to 22.3 degrees API gravity
Last in first out (“LIFO”)
Last in first out accounting assumes that crude oil feedstock costs are based on the current month price of WTI
Light crude oil
Crude oil with a relative density greater than 31.1 degrees API gravity
Medium
crude oil
Crude oil with a relative density that is greater than 22.3 degrees API gravity and less than or equal to 31.1 degrees API gravity
Net Debt
Total debt less cash and cash equivalents
Net Revenue
Gross revenue less royalties
NOVA Inventory Transfer (“NIT”)
Exchange
or transfer of title of gas that has been received into the NOVA pipeline system but not yet delivered to a connecting pipeline
Oil sands
Sands and other rock materials that contain crude bitumen and include all other associated mineral substances
Seismic survey
A method by which the physical attributes in the outer rock shell of the earth are determined by measuring, with a seismograph, the rate of transmission of shock waves through the various rock formations
Shareholders’ Equity
Common
shares, preferred shares, contributed surplus, retained earnings, accumulated other comprehensive income and non-controlling interest
Stratigraphic Well
A geologically directed test well to obtain information. These wells are usually drilled without the intention of being completed for production
Synthetic Oil
A mixture of hydrocarbons derived by upgrading heavy crude oils, including bitumen, through a process that reduces the carbon content and increases the hydrogen content
Thermal
Use
of steam injection into the reservoir in order to enable heavy oil and bitumen to flow to the well bore
Total Debt
Long-term debt, including long-term debt due within one year, and short-term debt
Turnaround
Performance of scheduled plant or facility maintenance requiring the complete or partial shutdown of the plant or facility operations
Western Canada
Includes Upstream
oil and gas exploration and development activities located in Alberta, Saskatchewan and British Columbia
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 30
Units of Measure
bbls
barrels
mboe/day
thousand
barrels of oil equivalent per day
bbls/day
barrels per day
mcf
thousand cubic feet
boe
barrels of oil equivalent
mmbbls
million barrels
boe/day
barrels of oil equivalent per day
mmboe
million
barrels of oil equivalent
GJ
gigajoule
mmbtu
million British Thermal Units
mbbls
thousand barrels
mmcf
million cubic feet
mbbls/day
thousand barrels per day
mmcf/day
million
cubic feet per day
mboe
thousand barrels of oil equivalent
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 31
Dates Referenced Herein and Documents Incorporated by Reference
