Exhibit
MANAGEMENT’S DISCUSSION AND ANALYSIS
October 24, 2019
Table of Contents
|
| | |
1.0 | | Summary of Quarterly Results |
2.0 | | Business Overview |
3.0 | | Business Environment |
4.0 | | Results of Operations |
5.0 | | Risk Management and Financial Risks |
6.0 | | Liquidity and Capital Resources |
7.0 | | Critical Accounting Estimates and Key Judgments |
8.0 | | 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) | 2019 |
| 2019 |
| 2019 |
| 2018 |
| 2018 |
| 2018 |
| 2018 |
| 2017 |
|
Production (mboe/day) | 294.8 |
| 268.4 |
| 285.2 |
| 304.3 |
| 296.7 |
| 295.5 |
| 300.4 |
| 320.4 |
|
Gross revenues and Marketing and other | 5,394 |
| 5,386 |
| 4,645 |
| 5,042 |
| 6,300 |
| 5,983 |
| 5,262 |
| 5,534 |
|
Net earnings | 273 |
| 370 |
| 328 |
| 216 |
| 545 |
| 448 |
| 248 |
| 672 |
|
Per share – Basic | 0.26 |
| 0.36 |
| 0.32 |
| 0.21 |
| 0.53 |
| 0.44 |
| 0.24 |
| 0.66 |
|
Per share – Diluted | 0.25 |
| 0.36 |
| 0.31 |
| 0.16 |
| 0.53 |
| 0.44 |
| 0.24 |
| 0.66 |
|
Cash flow – operating activities | 800 |
| 760 |
| 545 |
| 1,313 |
| 1,283 |
| 1,009 |
| 529 |
| 1,351 |
|
Funds from operations(1) | 1,021 |
| 802 |
| 959 |
| 583 |
| 1,318 |
| 1,208 |
| 895 |
| 1,014 |
|
Per share – Basic | 1.02 |
| 0.80 |
| 0.95 |
| 0.58 |
| 1.31 |
| 1.20 |
| 0.89 |
| 1.01 |
|
Per share – Diluted | 1.02 |
| 0.80 |
| 0.95 |
| 0.58 |
| 1.31 |
| 1.20 |
| 0.89 |
| 1.01 |
|
| |
(1) | Funds from operations is a non-GAAP measure. Refer to Section 10.3 for a reconciliation to the corresponding GAAP measure. |
Performance
| |
• | Net earnings of $273 million in the third quarter of 2019 compared to net earnings of $545 million in the third quarter of 2018, with the decrease primarily due to: |
| |
• | Lower earnings from Upstream operations due to lower global crude oil benchmark prices and lower production; |
| |
• | Lower earnings from crude oil marketing activities due to the tightening of location pricing differentials between Canada and the U.S.; and |
| |
• | Lower realized Upgrading and U.S. Refining margins. |
| |
• | Cash flow – operating activities and funds from operations, which excludes changes in working capital, were $800 million and $1,021 million, respectively, in the third quarter of 2019 compared to $1,283 million and $1,318 million, respectively, in the third quarter of 2018, with the decrease primarily attributed to the same factors noted above for net earnings. |
| |
• | Production decreased by 1.9 mboe/day or one percent to 294.8 mboe/day in the third quarter of 2019 compared to the third quarter of 2018 primarily due to: |
| |
• | Lower production from the Liwan Gas Project due to planned maintenance; |
| |
• | Lower production from the BD Project due to unplanned maintenance at the BD floating production, storage and offloading ("FPSO") vessel; |
| |
• | Lower heavy crude oil production due to government-mandated production quotas in Alberta and natural declines; and |
| |
• | Lower production from Atlantic due to lower production from the White Rose field, which resumed full production in mid-August 2019. |
Partially offset by:
| |
• | Higher bitumen production from the Company's thermal projects; and |
| |
• | Higher natural gas and natural gas liquids (“NGL”) production from Western Canada. |
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 1
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 generate returns from investing in a deep portfolio of projects and investment opportunities across 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”). These investments provide for increasing margins, funds from operations and earnings. A strong balance sheet, deep physical integration and largely fixed price contracts in Asia Pacific provide resilience to market volatility while preserving upside.
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, Husky Midstream Limited Partnership (35 percent working interest and operatorship), and the Lima, Superior, and Toledo (50 percent working interest) refineries in the U.S. Midwest. Natural gas production from the Western Canada portfolio supplies 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 the marketing of the Company’s and other producers’ crude oil, natural gas, NGL, sulphur and petroleum coke. Additionally, Upstream operations include 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 primarily in Western Canada, Atlantic and Asia Pacific.
Exploration and Production
Thermal Developments
The Company continued to advance its inventory of thermal projects in the third quarter of 2019, with the commencement of production at its Dee Valley thermal project in Saskatchewan, the second of seven 10,000-barrel-per-day thermal bitumen projects scheduled to be brought onstream from 2018-2023. These long-life developments are being built with modular, repeatable designs and require low sustaining capital once brought online.
Total thermal bitumen production, including Lloyd thermal projects, the Tucker Thermal Project and the Sunrise Energy Project, averaged 126,400 bbls/day (Husky working interest) in the third quarter of 2019. Production for the quarter was impacted by government-mandated production quotas in Alberta and planned turnarounds at three of the Saskatchewan thermal plants.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 2
Lloyd Thermal Bitumen Projects
The following table shows the major projects and their status as at September 30, 2019:
|
| | | |
Project Name | Nameplate Capacity (bbls/day) | Expected Project Production Date | Project Status |
Dee Valley | 10,000 | On production | First steam was achieved on June 30, 2019, with first oil achieved on August 24, 2019, and reached nameplate capacity on September 30, 2019. |
Spruce Lake Central | 10,000 | Second half of 2020 | Module setting has been completed and the Central Processing Facility plant is expected to be completed by the end of 2019. Piling has been completed on well pads and flow lines. |
Spruce Lake North | 10,000 | Around the end of 2020 | Site piling and concrete work have been completed. Module fabrication is on schedule and module setting has begun with the Once-Through Steam Generators delivered and set on site. |
Spruce Lake East | 10,000 | Around the end of 2021 | Regulatory approval has been received, and lease construction has been completed. |
Edam Central | 10,000 | 2022 | Regulatory approval has been received. |
Dee Valley 2 | 10,000 | 2023 | Regulatory approval has been received. |
Tucker Thermal Project
Production in the third quarter of 2019 averaged 23,000 bbls/day and was impacted by the government-mandated production quotas in Alberta.
Sunrise Energy Project
Total production in the third quarter of 2019 averaged 53,000 bbls/day (26,500 bbls/day Husky working interest) and was impacted by the government-mandated production quotas in Alberta.
Western Canada
Oil and Natural Gas Resource Plays
The Company drilled one well at Karr, which completed the 2019 Montney drilling program. The Company expects 10 Montney wells at Wembley and Karr to be on production by the end of 2019.
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 ongoing investment in Enhanced Oil Recovery (“EOR”) projects. The Aberfeldy EOR Polymer Project began operations in August 2019.
Asia Pacific
China
Block 29/26
Total production from Liwan 3-1 and Liuhua 34-2 averaged 68,200 boe/day (33,000 boe/day Husky working interest) in the third quarter of 2019. Total production consisted of natural gas production of 323.2 mmcf/day and NGL production of 14,300 bbls/day.
Construction continues at Liuhua 29-1, the third deepwater gas field of the Liwan Gas Project. Three of the seven wells were fully completed and prepared for production. The upper completion of the remaining four wells is to be installed in the fourth quarter of 2019. The initial infield pipe lay program was completed in August 2019, and the control system and flow lines are to be installed in 2020. First gas production from Liuhua 29-1 development is expected by the end of 2020.
Block 15/33
The Company is progressing commercial development plans following the successful drilling and testing of an exploration well on Block 15/33. Additional appraisal work is being considered on the block and the block boundaries have been extended.
The Company is the operator of the block 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 the block for the development and production phases.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 3
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. Initial evaluation work of existing data on these two blocks is currently being carried out to assess exploration potential.
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
Total production averaged 21,300 boe/day (8,500 boe/day Husky working interest) in the third quarter of 2019. Total production consisted of natural gas production of 85.6 mmcf/day and NGL production of 7,000 bbls/day.
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. Gas production and sales are expected to commence in 2021. Subsequently, an additional shallow water field, named MDK, is scheduled to be developed via a separate platform and tied into the MDA and MBH infrastructure. 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.
Atlantic
White Rose Field and Satellite Extensions
Full production was restored to the White Rose field and satellite extensions in mid-August, following regulatory approvals to resume operations from the South White Rose Extension (“SWRX”) and North Amethyst Drill Centres. Production from these drill centres had been suspended since November 2018, due to a spill from a flowline connector at the SWRX. The flowline connector has since been replaced. The field has now ramped up to rates of approximately 20,000 bbls/day (Husky working interest).
Construction continued on the Concrete Gravity Structure for the West White Rose Project. A third planned slipform was completed at the dry-dock in Argentia, Newfoundland and Labrador, and the first three interior decks were installed. A fourth slipform was completed in mid-October. First production is expected around the end of 2022.
Atlantic Exploration
The Company continued to evaluate the results of its 2018 discovery at the A-24 exploration well north of the White Rose field. 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
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.
Ansell Corser Plant
The new gas processing plant is under construction and is expected to add 120 mmcf/day of processing capacity when it is scheduled to come online in the fourth quarter of 2019.
Hardisty Tanks
Construction is underway for 1.5 mmbbls of storage at the Hardisty Terminal scheduled for completion by the end of 2020.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 4
Downstream Operations
Downstream operations in the Integrated Corridor in Canada includes upgrading of heavy crude oil feedstock into synthetic crude oil (“Upgrading”), refining crude oil, producing ethanol and marketing of heavy and synthetic crude oil, refined petroleum products including gasoline, diesel, ethanol blended fuels, asphalt and ancillary products (“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.
Canadian Refined Products
During the first quarter of 2019, the Company announced a strategic review to market and potentially sell the Prince George Refinery and its Canadian retail and commercial fuels business.
The Company reached an agreement on October 4, 2019 to sell its Prince George Refinery to Tidewater Midstream and Infrastructure for $215 million in cash plus a closing adjustment for inventory, and a contingent payment of up to $60 million over two years. The transaction is subject to regulatory approval and is expected to close in the fourth quarter of 2019.
The strategic review of the Company's retail and commercial fuels business continues to progress.
U.S. Refining and Marketing
Lima Refinery
Crude Oil Flexibility Project
The Company's crude oil flexibility project at the Lima Refinery 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. The Refinery entered into a planned turnaround in the third quarter of 2019 to complete the project. The project is expected to be completed by the end of 2019.
Superior Refinery
On April 26, 2018, the Superior Refinery experienced an incident while preparing for a major turnaround. Demolition and site preparation work progressed through 2019. Permits necessary for the rebuild were received by September 27, 2019 and rebuilding work began immediately. The investment in the rebuild is estimated to be more than US$400 million, of which the Company anticipates a substantial portion will be recovered from property damage insurance. The Company anticipates that lost income through April 2020 will be compensated by business interruption insurance. The refinery will be rebuilt with the same throughput capacity and will be able to produce a full slate of products, including asphalt, gasoline and diesel. Full operations are expected to resume in 2021.
2.3 Financial Strategic Plan
During the third quarter of 2019:
| |
• | The Board of Directors declared a quarterly dividend of $0.125 per common share, or $125 million, for the second quarter of 2019. The dividends were paid on October 1, 2019, to shareholders of record at the close of business on September 3, 2019; and |
| |
• | Dividends of $9 million were declared on preferred shares for the third quarter of 2019, and were paid on September 30, 2019, to shareholders of record at the close of business on September 3, 2019. |
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 5
3.0 Business Environment
Average Benchmarks
|
| | | | | | | | | | | | | | | | |
| | Three months ended | Nine months ended |
| | Sept. 30 |
| Jun. 30 |
| Mar. 31 |
| Dec. 31 |
| Sept. 30 |
| Sept. 30 |
| | Sept. 30 |
|
Average Benchmarks Summary | 2019 |
| 2019 |
| 2019 |
| 2018 |
| 2018 |
| 2019 |
| | 2018 |
|
West Texas Intermediate (“WTI”) crude oil(1) | (US$/bbl) | 56.45 |
| 59.82 |
| 54.90 |
| 58.81 |
| 69.50 |
| 57.06 |
| | 66.75 |
|
Brent crude oil(2) | (US$/bbl) | 61.94 |
| 68.82 |
| 63.20 |
| 67.54 |
| 75.23 |
| 64.65 |
| | 72.11 |
|
Light sweet at Edmonton | ($/bbl) | 68.41 |
| 73.85 |
| 66.53 |
| 42.68 |
| 81.92 |
| 69.60 |
| | 78.19 |
|
Western Canadian Select (“WCS”) at Hardisty(3) | (US$/bbl) | 44.21 |
| 49.14 |
| 42.61 |
| 19.38 |
| 47.25 |
| 45.32 |
| | 44.82 |
|
Lloyd heavy crude oil at Lloydminster | ($/bbl) | 54.84 |
| 61.71 |
| 52.12 |
| 12.83 |
| 54.01 |
| 56.22 |
| | 48.16 |
|
WTI/Lloyd crude blend differential | (US$/bbl) | 11.90 |
| 10.28 |
| 11.88 |
| 39.32 |
| 22.06 |
| 11.35 |
| | 21.68 |
|
Condensate at Edmonton | (US$/bbl) | 52.02 |
| 55.86 |
| 50.56 |
| 45.28 |
| 66.65 |
| 52.81 |
| | 66.17 |
|
NYMEX natural gas(4) | (US$/mmbtu) | 2.39 |
| 2.64 |
| 3.15 |
| 3.64 |
| 2.90 |
| 2.73 |
| | 2.90 |
|
NOVA Inventory Transfer (“NIT”) natural gas | ($/GJ) | 0.99 |
| 1.11 |
| 1.84 |
| 1.80 |
| 1.28 |
| 1.31 |
| | 1.34 |
|
Chicago Regular Unleaded Gasoline | (US$/bbl) | 71.71 |
| 81.40 |
| 63.41 |
| 67.34 |
| 86.61 |
| 72.27 |
| | 81.55 |
|
Chicago Ultra-low Sulphur Diesel | (US$/bbl) | 75.26 |
| 81.50 |
| 77.10 |
| 85.42 |
| 92.21 |
| 77.96 |
| | 87.62 |
|
Chicago 3:2:1 crack spread | (US$/bbl) | 16.44 |
| 21.61 |
| 13.08 |
| 13.38 |
| 19.04 |
| 17.11 |
| | 16.78 |
|
U.S./Canadian dollar exchange rate | (US$) | 0.757 |
| 0.748 |
| 0.752 |
| 0.757 |
| 0.765 |
| 0.752 |
| | 0.777 |
|
Canadian $ Equivalents(5) | | | | | | | | | |
WTI crude oil | ($/bbl) | 74.57 |
| 79.97 |
| 73.01 |
| 77.69 |
| 90.85 |
| 75.88 |
| | 85.91 |
|
Brent crude oil | ($/bbl) | 81.82 |
| 92.00 |
| 84.04 |
| 89.22 |
| 98.34 |
| 85.97 |
| | 92.81 |
|
WCS at Hardisty | ($/bbl) | 58.40 |
| 65.70 |
| 56.66 |
| 25.60 |
| 61.76 |
| 60.27 |
| | 57.68 |
|
WTI/Lloyd crude blend differential | ($/bbl) | 15.72 |
| 13.74 |
| 15.80 |
| 51.94 |
| 28.84 |
| 15.09 |
| | 27.90 |
|
NYMEX natural gas | ($/mmbtu) | 3.16 |
| 3.53 |
| 4.19 |
| 4.81 |
| 3.79 |
| 3.63 |
| | 3.73 |
|
| |
(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 2019 decreased relative to the third quarter of 2018. WTI averaged US$56.45/bbl during the third quarter of 2019, compared to US$69.50/bbl during the third quarter of 2018. Brent averaged US$61.94/bbl during the third quarter of 2019, compared to US$75.23/bbl during the third quarter of 2018. WCS averaged US$44.21/bbl during the third quarter of 2019, compared to US$47.25/bbl during the third quarter of 2018.
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 for location and quality. 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 significant 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 75 percent heavy crude oil and bitumen in the third quarter of 2019 compared to 72 percent in the third quarter of 2018.
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 decreased in the third quarter of 2019 compared to the third quarter of 2018, primarily due to the decrease in crude oil benchmark pricing.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 6
Natural Gas Benchmarks
The price received by the Company for natural gas production from Western Canada is largely driven by the NIT near-month contract price of natural gas and the location differential (net of transportation costs) between NIT and the market prices in the hubs at the end of the Company's long-haul export pipelines. The price received by the Company for production from Asia Pacific is determined by long-term 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 a key indicator for U.S. Midwest 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 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 and BP-Husky Toledo refineries contain approximately 14 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$0.757 in the third quarter of 2019 compared to US$0.765 in the third quarter of 2018.
A portion of the Company’s long-term sales contracts in Asia Pacific are priced in Chinese Yuan (“RMB”). An increase in the value of the Canadian dollar relative to the RMB will decrease the revenues received in Canadian dollars from the sale of natural gas commodities in the region. The Canadian dollar averaged RMB 5.315 in the third quarter of 2019 compared to RMB 5.209 in the third quarter of 2018.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 7
Sensitivity Analysis
The following table is indicative of the impact of changes in certain key variables in the third quarter of 2019 on earnings before income taxes and net earnings on an annualized basis. The table below reflects what the effect would have been on the financial results had the indicated variable increased by the notional amount. The analysis is based on business conditions and production volumes during the third quarter of 2019. Each separate item in the sensitivity analysis shows the approximate effect of an increase in that variable only; all other variables are held constant. While these sensitivities are indicative for the period and magnitude of changes on which they are based, they may not be applicable in other periods, under other economic circumstances or upon greater magnitudes of change.
|
| | | | | | | | | | | | | | |
| 2019 |
| | | | | | |
| Third Quarter |
| | | | Effect on Earnings | | Effect on |
Sensitivity Analysis | Average |
| | Increase | | before Income Taxes(1) | | Net Earnings(1) |
| | | | | ($ millions) |
| ($/share)(2) |
| | ($ millions) |
| ($/share)(2) |
|
WTI benchmark crude oil price(3)(4) | 56.45 |
| | US $1.00/bbl | | 95 |
| 0.09 |
| | 70 |
| 0.07 |
|
NYMEX benchmark natural gas price(5) | 2.39 |
| | US $0.20/mmbtu | | — |
| — |
| | — |
| — |
|
WTI/Lloyd crude blend differential(6) | 11.90 |
| | US $1.00/bbl | | (4 | ) | — |
| | (3 | ) | — |
|
Canadian asphalt margins | 28.39 |
| | Cdn $1.00/bbl | | 13 |
| 0.01 |
| | 10 |
| 0.01 |
|
Canadian light oil margins | 0.038 |
| | Cdn $0.005/litre | | 14 |
| 0.01 |
| | 10 |
| 0.01 |
|
Chicago 3:2:1 crack spread | 16.44 |
| | US $1.00/bbl | | 116 |
| 0.12 |
| | 90 |
| 0.09 |
|
Exchange rate (US $ per Cdn $)(3)(7) | 0.757 |
| | US $0.01 | | (78 | ) | (0.08 | ) | | (58 | ) | (0.06 | ) |
| |
(1) | Excludes mark to market accounting impacts. |
| |
(2) | Based on 1,005.1 million common shares outstanding as at September 30, 2019. |
| |
(3) | Does not include gains or losses on inventory. |
| |
(4) | Includes impacts related to Brent-based production. |
| |
(5) | Includes impact of natural gas consumption by the Company. |
| |
(6) | Excludes impact on Canadian asphalt operations. |
| |
(7) | Assumes no foreign exchange gains or losses on U.S. dollar denominated long-term debt and other monetary items, including cash balances. |
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 8
4.0 Results of Operations
4.1 Upstream
Exploration and Production
|
| | | | | | | | | | | |
Exploration and Production Earnings Summary | Three months ended September 30, | | | Nine months ended September 30, | |
($ millions) | 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
Gross revenues | 1,241 |
| | 1,319 |
| | 3,677 |
| | 3,687 |
|
Royalties | (81 | ) | | (106 | ) | | (235 | ) | | (285 | ) |
Net revenues | 1,160 |
| | 1,213 |
| | 3,442 |
| | 3,402 |
|
Purchases of crude oil and products | — |
| | — |
| | — |
| | 1 |
|
Production, operating and transportation expenses | 399 |
| | 398 |
| | 1,199 |
| | 1,139 |
|
Selling, general and administrative expenses | 78 |
| | 71 |
| | 226 |
| | 224 |
|
Depletion, depreciation, amortization and impairment (“DD&A”) | 497 |
| | 461 |
| | 1,349 |
| | 1,342 |
|
Exploration and evaluation expenses | 41 |
| | 26 |
| | 157 |
| | 96 |
|
Loss (gain) on sale of assets | — |
| | 2 |
| | (2 | ) | | (2 | ) |
Other – net | (18 | ) | | (42 | ) | | 97 |
| | (11 | ) |
Share of equity investment gain | (15 | ) | | (12 | ) | | (42 | ) | | (33 | ) |
Financial items | 39 |
| | 27 |
| | 121 |
| | 68 |
|
Provisions for income taxes | 33 |
| | 68 |
| | 79 |
| | 149 |
|
Net earnings | 106 |
| | 214 |
| | 258 |
| | 429 |
|
Third Quarter
Exploration and Production net revenues decreased by $53 million in the third quarter of 2019 compared to the third quarter of 2018, primarily due to lower average realized sales prices and lower production, both of which are described in more detail below.
Provisions for income taxes decreased by $35 million in the third quarter of 2019 compared to the third quarter of 2018, primarily due to lower earnings before income taxes in the third quarter of 2019.
Nine Months
Exploration and Production net revenues increased by $40 million compared to the same period in 2018, primarily due to higher average realized sales prices, partially offset by lower production, both of which are described in more detail below.
Exploration and evaluation expenses increased by $61 million compared to the same period in 2018, primarily due to higher expensed drilling, which is described in more detail in the Exploration and Evaluation Expenses section.
Other – net increased by $108 million compared to the same period in 2018, primarily due to profit or loss elimination between segments.
Financial items increased by $53 million compared to the same period in 2018, primarily due to higher finance expenses arising from the adoption of IFRS 16 in 2019.
Provisions for income taxes decreased by $70 million compared to the same period in 2018, primarily due to the same factors which impacted the third quarter.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 9
Average Sales Prices Realized
|
| | | | | | | | | | | |
| Three months ended September 30, | | | Nine months ended September 30, | |
Average Sales Prices Realized | 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
Crude oil and NGL ($/bbl) | | | | | | | |
Light and Medium crude oil | 71.32 |
| | 93.84 |
| | 73.44 |
| | 89.04 |
|
NGL(1) | 38.39 |
| | 60.08 |
| | 44.74 |
| | 56.61 |
|
Heavy crude oil | 56.70 |
| | 50.09 |
| | 56.54 |
| | 45.48 |
|
Bitumen | 51.09 |
| | 46.00 |
| | 51.88 |
| | 39.35 |
|
Total crude oil and NGL average | 53.46 |
| | 56.02 |
| | 54.15 |
| | 49.99 |
|
Natural gas average ($/mcf)(1) | 5.44 |
| | 6.15 |
| | 6.25 |
| | 6.55 |
|
Total average ($/boe) | 47.54 |
| | 50.44 |
| | 49.26 |
| | 47.02 |
|
| |
(1) | Reported average NGL and natural gas prices 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
The average sales prices realized by the Company for crude oil and NGL production decreased by five percent in the third quarter of 2019 compared to the third quarter of 2018, primarily due to lower global benchmark crude oil prices and lower realized NGL prices, partially offset by the narrowing of the Canadian light/heavy oil differential.
The average sales prices realized by the Company for natural gas production decreased by 12 percent in the third quarter of 2019 compared to the third quarter of 2018, primarily due to lower production from the Liwan Gas Project.
Nine Months
The average sales prices realized by the Company for crude oil and NGL production increased by eight percent compared to the same period in 2018, primarily due to the narrowing the Canadian light/heavy oil differential, partially offset by the lower global benchmark crude oil prices.
The average sales prices realized by the Company for natural gas production decreased by five percent compared to the same period in 2018, 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 | 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
Crude Oil and NGL (mbbls/day) | | | | | | | |
Western Canada | | | | | | | |
Light and Medium crude oil | 9.4 |
| | 9.9 |
| | 8.6 |
| | 9.4 |
|
NGL | 13.0 |
| | 11.9 |
| | 12.7 |
| | 11.8 |
|
Heavy crude oil | 31.6 |
| | 34.6 |
| | 29.4 |
| | 37.6 |
|
Bitumen(1) | 126.4 |
| | 117.3 |
| | 125.7 |
| | 121.2 |
|
| 180.4 |
| | 173.7 |
| | 176.4 |
| | 180.0 |
|
Atlantic | | | | | | | |
White Rose and Satellite Fields – light crude oil | 16.4 |
| | 21.0 |
| | 9.3 |
| | 20.0 |
|
Terra Nova – light crude oil | 4.7 |
| | 2.8 |
| | 4.4 |
| | 4.3 |
|
| 21.1 |
| | 23.8 |
| | 13.7 |
| | 24.3 |
|
Asia Pacific | | | | | | | |
Liwan – NGL(2) | 6.6 |
| | 8.4 |
| | 7.1 |
| | 8.1 |
|
Madura –NGL(3) | 2.8 |
| | 4.2 |
| | 2.6 |
| | 2.3 |
|
| 9.4 |
|
| 12.6 |
| | 9.7 |
| | 10.4 |
|
| 210.9 |
| | 210.1 |
| | 199.8 |
| | 214.7 |
|
Natural gas (mmcf/day) | | | | | | | |
Western Canada | 310.4 |
| | 297.6 |
| | 297.2 |
| | 287.2 |
|
Asia Pacific | | | | | | | |
Liwan(2) | 158.3 |
| | 181.9 |
| | 166.7 |
| | 180.6 |
|
Madura(3) | 34.6 |
| | 40.0 |
| | 34.3 |
| | 29.2 |
|
| 192.9 |
| | 221.9 |
| | 201.0 |
| | 209.8 |
|
| 503.3 |
| | 519.5 |
| | 498.2 |
| | 497.0 |
|
Total (mboe/day) | 294.8 |
| | 296.7 |
| | 282.8 |
| | 297.5 |
|
| |
(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 production 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 increased by 0.8 mbbls/day in the third quarter of 2019 compared to the third quarter of 2018, primarily due to increased bitumen production from the Company’s thermal projects combined with increased NGL production from Western Canada. The increases were partially offset by lower production from Asia Pacific due to planned maintenance at Liwan Gas Project and lower production from the BD Project due to unplanned maintenance at the BD FPSO, a reduction of heavy crude oil production due to government-mandated production quotas in Alberta and natural declines, and lower production from Atlantic due to the suspension of production from the SWRX and North Amethyst Drill Centres at the White Rose field (with full production restored in mid-August 2019).
Nine Months
Crude oil and NGL production decreased by 14.9 mbbls/day compared to the same period in 2018, primarily due to lower production from Atlantic due to the suspension of production from the White Rose field combined with a reduction of heavy crude oil production due to government-mandated production quotas in Alberta and natural declines. The decreases were partially offset by increased bitumen production from the Company’s thermal projects, combined with increased NGL production from Western Canada.
Natural Gas Production
Third Quarter
Natural gas production decreased by 16.2 mmcf/day in the third quarter of 2019 compared to the third quarter of 2018, primarily due to lower production from the Liwan Gas Project due to planned maintenance in the third quarter of 2019. The decrease was partially offset by the higher production at the Rainbow Lake development.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 11
Nine Months
Natural gas production increased by 1.2 mmcf/day compared to the same period in 2018, primarily due to higher production from the BD Project and the Rainbow Lake development, which was partially offset by the same factors which impacted the third quarter .
2019 Production Guidance
The following table shows actual daily production for the nine months ended September 30, 2019, and the year ended December 31, 2018, as well as the previously issued production guidance for 2019.
|
| | | | | | | |
| | | Actual Production |
| Guidance | | Nine months ended |
| | Year ended |
|
Gross Production | 2019 | | September 30, 2019 |
| | December 31, 2018 |
|
Canada | | | | | |
Light & medium crude oil (mbbls/day) | 29 - 31 | | 22 |
| | 31 |
|
NGL (mbbls/day) | 12 - 13 | | 13 |
| | 12 |
|
Heavy crude oil & bitumen (mbbls/day) | 155 - 163 | | 155 |
| | 161 |
|
Natural gas (mmcf/day) | 297 - 307 | | 297 |
| | 291 |
|
Canada total (mboe/day) | 246 - 258 | | 240 |
| | 252 |
|
Asia Pacific | | | | | |
NGL (mbbls/day)(1) | 9 - 10 | | 10 |
| | 11 |
|
Natural gas (mmcf/day)(1) | 210 - 220 | | 201 |
| | 216 |
|
Asia Pacific total (mboe/day) | 44 - 47 | | 43 |
| | 47 |
|
Total (mboe/day) | 290 - 305 | | 283 |
| | 299 |
|
| |
(1) | Includes Husky’s working interest production 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. |
Production for the nine months ended September 30, 2019 reflects planned turnarounds, ongoing government-mandated production quotas in Alberta and a staged restart of White Rose operations. The last quarter of the year is expected to have higher production volumes as the Company exits the turnaround season, and fully ramps up production at White Rose and the Dee Valley thermal project in Saskatchewan.
Royalties
|
| | | | | | | | | |
Royalties | Three months ended September 30, | | | Nine months ended September 30, | |
(Percent) | 2019 | | 2018 |
| | 2019 | | 2018 |
|
Western Canada(1) | 7 | | 9 |
| | 7 | | 9 |
|
Atlantic | 8 | | 8 |
| | 10 | | 8 |
|
Asia Pacific(2) | 7 | | 7 |
| | 7 | | 7 |
|
Total | 7 | | 8 |
| | 7 | | 8 |
|
| |
(1) | Includes thermal and non-thermal developments. |
| |
(2) | 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 decreased in the third quarter of 2019 compared to the third quarter of 2018, primarily due to lower royalty rates from Western Canada as a result of a gas cost allowance credit which reduced the net royalty rate in the third quarter of 2019.
Nine Months
Total royalty rates decreased compared to the same period in 2018, primarily due to lower royalty rates from thermal developments as a result of a change to pre-payout status of a thermal property in the first quarter of 2019, combined with the same factors which impacted the third quarter. The decrease was partially offset by increased royalty rates for Atlantic compared to the same period in 2018, primarily due to a higher proportion of production from the Terra Nova field, which has a higher royalty rate.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 12
Operating Costs |
| | | | | | | | | | | |
Operating Costs | Three months ended September 30, | | | Nine months ended September 30, | |
($ millions) | 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
Western Canada(1) | 316 |
| | 318 |
| | 950 |
| | 917 |
|
Atlantic | 63 |
| | 55 |
| | 184 |
| | 156 |
|
Asia Pacific (2) | 24 |
| | 28 |
| | 73 |
| | 70 |
|
Total | 403 |
| | 401 |
| | 1,207 |
| | 1,143 |
|
Per unit operating costs ($/boe) | 14.83 |
| | 14.68 |
| | 15.63 |
| | 14.08 |
|
| |
(1) | Includes thermal and non-thermal developments. |
| |
(2) | 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 $403 million in the third quarter of 2019 compared to $401 million in the third quarter of 2018. Total per unit operating costs averaged $14.83/boe in the third quarter of 2019 compared to $14.68/boe in the third quarter of 2018. The increase in per unit operating costs was primarily due to the factors discussed below.
Per unit operating costs in Atlantic averaged $32.21/bbl in the third quarter of 2019 compared to $25.22/bbl in the third quarter of 2018. The increase in per unit operating costs was primarily due to lower production and additional well workover scope at the White Rose field.
Per unit operating costs in Western Canada averaged $14.76/boe in the third quarter of 2019 compared to $15.48/boe in the third quarter of 2018. The decrease 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 Asia Pacific averaged $6.39/boe in the third quarter of 2019 compared to $5.98/boe in the third quarter of 2018. The increase in per unit operating costs was primarily due to lower production, combined with higher maintenance costs from the Liwan Gas Project in the third quarter of 2019.
Nine Months
Total Exploration and Production operating costs were $1,207 million compared to $1,143 million in the same period in 2018. Total per unit operating costs averaged $15.63/boe compared to $14.08/boe in the same period in 2018. The increase in per unit operating costs was primarily due to the factors discussed below.
Per unit operating costs in Atlantic averaged $49.24/bbl compared to $23.51/bbl in the same period in 2018. The increase in per unit operating costs was primarily due to the costs associated with the flowline repair, combined with the same factors which impacted the third quarter.
Per unit operating costs in Western Canada averaged $15.41/boe compared to $14.76/boe in the same period in 2018. The increase in per unit operating costs was primarily due to higher natural gas costs and lower production.
Per unit operating costs in Asia Pacific averaged $6.23/boe compared to $5.62/boe in the same period in 2018. The increase in per unit operating costs was primarily due to planned maintenance at the Liwan Gas Project in the first quarter of 2019, combined with the same factors which impacted the third quarter.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 13
Exploration and Evaluation Expenses
|
| | | | | | | | | | | |
Exploration and Evaluation Expenses | Three months ended September 30, | | | Nine months ended September 30, | |
($ millions) | 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
Seismic, geological and geophysical | 34 |
| | 22 |
| | 86 |
| | 70 |
|
Expensed drilling | 5 |
| | 1 |
| | 65 |
| | 21 |
|
Expensed land | 2 |
| | 3 |
| | 6 |
| | 5 |
|
Total | 41 |
| | 26 |
| | 157 |
| | 96 |
|
Third Quarter
Exploration and Evaluation expenses in the third quarter of 2019 were $41 million compared to $26 million in the third quarter of 2018. The increase in seismic, geological and geophysical expenses was primarily due to increased pre-development activities in Western Canada and Atlantic.
Nine Months
Exploration and Evaluation expenses in the first nine months of 2019 were $157 million compared to $96 million in the same period in 2018. The increase in expensed drilling was primarily due to the write off of exploration wells in Atlantic and Asia Pacific in the second quarter of 2019, combined with the same factors which impacted the third quarter.
Exploration and Production Capital Expenditures
Exploration and Production capital expenditures were higher in the first nine months of 2019 compared to the first nine months of 2018, primarily due to the factors discussed below. Exploration and Production capital expenditures were as follows:
|
| | | | | | | | | | | |
Exploration and Production Capital Expenditures(1) | Three months ended September 30, | | | Nine months ended September 30, | |
($ millions) | 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
Exploration | | | | | | | |
Western Canada | 7 |
| | 32 |
| | 7 |
| | 65 |
|
Thermal developments | 2 |
| | — |
| | 15 |
| | 3 |
|
Atlantic | 1 |
| | 6 |
| | 12 |
| | 65 |
|
Asia Pacific(2) | 1 |
| | 18 |
| | 3 |
| | 52 |
|
| 11 |
| | 56 |
| | 37 |
| | 185 |
|
Development | | | | | | | |
Western Canada | 24 |
| | 100 |
| | 178 |
| | 226 |
|
Thermal developments | 161 |
| | 234 |
| | 541 |
| | 577 |
|
Non-thermal developments | 23 |
| | 24 |
| | 81 |
| | 54 |
|
Atlantic | 274 |
| | 255 |
| | 696 |
| | 592 |
|
Asia Pacific(2) | 104 |
| | 45 |
| | 249 |
| | 80 |
|
| 586 |
| | 658 |
| | 1,745 |
| | 1,529 |
|
Acquisitions | | | | | | | |
Western Canada | — |
| | — |
| | — |
| | 4 |
|
Thermal developments | — |
| | 1 |
| | — |
| | 40 |
|
| — |
| | 1 |
| | — |
| | 44 |
|
Total | 597 |
| | 715 |
| | 1,782 |
| | 1,758 |
|
| |
(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
During the first nine months of 2019, $185 million (10 percent) was invested in Western Canada, compared to $295 million (17 percent) in the same period in 2018. Capital expenditures in 2019 related primarily to resource play development targeting the Spirit River Formation at the Ansell and Kakwa areas and the Montney Formation at the Wembley and Sinclair areas.
Thermal Developments
During the first nine months of 2019, $556 million (31 percent) was invested in thermal developments compared to $620 million (35 percent) in the same period in 2018. Capital expenditures in 2019 related primarily to construction work at the Dee Valley, Spruce Lake Central and North thermal projects.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 14
Non-Thermal Developments
During the first nine months of 2019, $81 million (five percent) was invested in non-thermal developments compared to $54 million (three percent) in the same period in 2018. Capital expenditures in 2019 related primarily to drilling and advancing the Company's EOR program, particularly the Aberfeldy Polymer Project.
Atlantic
During the first nine months of 2019, $708 million (40 percent) was invested in Atlantic compared to $657 million (37 percent) in the same period in 2018. Capital expenditures in 2019 related primarily to the development of the West White Rose Project and sustainment and development activities at the White Rose field.
Asia Pacific
During the first nine months of 2019, $252 million (14 percent) was invested in Asia Pacific compared to $132 million (eight percent) in the same period in 2018. Capital expenditures in 2019 related primarily to the continued development of Liuhua 29-1.
Exploration and Production Wells Drilled
Onshore drilling activity
The following table discloses the number of wells drilled during the three and nine months ended September 30, 2019 and 2018:
|
| | | | | | | | | | | | | | | | | | | |
| Three months ended September 30, | | Nine months ended September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
Wells Drilled (wells)(1) | Gross |
| Net |
| | Gross |
| Net |
| | Gross |
| Net |
| | Gross |
| Net |
|
Thermal developments | 13 |
| 10 |
| | 52 |
| 48 |
| | 60 |
| 57 |
| | 112 |
| 101 |
|
Non-thermal developments | 7 |
| 7 |
| | 5 |
| 1 |
| | 29 |
| 29 |
| | 9 |
| 5 |
|
Western Canada | 1 |
| 1 |
| | 15 |
| 14 |
| | 17 |
| 15 |
| | 26 |
| 24 |
|
Total | 21 |
| 18 |
| | 72 |
| 63 |
| | 106 |
| 101 |
| | 147 |
| 130 |
|
| |
(1) | Excludes service/stratigraphic test wells for evaluation purposes. |
Offshore drilling activity
The following table discloses the Company’s Offshore drilling activity during the nine months ended September 30, 2019:
|
| | | |
Region | Well | Working Interest | Well Type |
Atlantic | E-18 13 | 72.5 percent | Development |
Atlantic | E-18 14 | 72.5 percent | Development |
Atlantic | Tiger's Eye D-17 | 40 percent | Exploration |
Asia Pacific | LH 29-1-A3 | 75 percent | Development |
Asia Pacific | LH 29-1-A1 | 75 percent | Development |
Asia Pacific | LH 29-1-A2 | 75 percent | Development |
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 15
Infrastructure and Marketing
|
| | | | | | | | | | | |
Infrastructure and Marketing Earnings Summary | Three months ended September 30, | | | Nine months ended September 30, | |
($ millions) | 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
Gross revenues | 676 |
| | 601 |
| | 1,734 |
| | 1,681 |
|
Marketing and other | 35 |
| | 168 |
| | 179 |
| | 520 |
|
Expenses | | | | | | | |
Purchases of crude oil and products | 658 |
| | 567 |
| | 1,745 |
| | 1,590 |
|
Production, operating and transportation expenses | 4 |
| | 2 |
| | 12 |
| | 19 |
|
Selling, general and administrative expenses | — |
| | 1 |
| | 3 |
| | 3 |
|
Depletion, depreciation, amortization and impairment | 4 |
| | — |
| | 10 |
| | 1 |
|
Other – net | — |
| | (1 | ) | | — |
| | 1 |
|
Share of equity investment gain | (4 | ) | | (6 | ) | | (22 | ) | | (20 | ) |
Financial items | 2 |
| | — |
| | 2 |
| | — |
|
Provisions for income taxes | 13 |
| | 57 |
| | 44 |
| | 166 |
|
Net earnings | 34 |
| | 149 |
| | 119 |
| | 441 |
|
Third Quarter
Infrastructure and Marketing gross revenues and purchases of crude oil and products increased by $75 million and $91 million, respectively, in the third quarter of 2019 compared to the third quarter of 2018, primarily due to increased volumes.
Marketing and other decreased by $133 million in the third quarter of 2019 compared to the third quarter of 2018, primarily due to the tightening of location pricing differentials between Canada and the U.S.
Provisions for income taxes decreased by $44 million in the third quarter of 2019 compared to the third quarter of 2018, primarily due to lower earnings before income taxes in the third quarter of 2019.
Nine Months
Infrastructure and Marketing gross revenues of $1,734 million were comparable to the $1,681 million reported in the same period in 2018.
Marketing and other decreased by $341 million compared to the same period in 2018, primarily due to the same factors which impacted the third quarter.
Infrastructure and Marketing purchases of crude oil and products increased by $155 million compared to the same period in 2018, primarily due to additional costs incurred on the construction of the Saskatchewan Gathering System Expansion in the second quarter of 2019, combined with the same factors which impacted the third quarter.
Provisions for income taxes decreased by $122 million compared to the same period in 2018, primarily due to the same factors which impacted the third quarter.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 16
4.2 Downstream
Upgrading
|
| | | | | | | | | | | |
Upgrading Earnings Summary | Three months ended September 30, | | | Nine months ended September 30, | |
($ millions, except where indicated) | 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
Gross revenues | 464 |
| | 534 |
| | 1,321 |
| | 1,443 |
|
Expenses | | | | | | | |
Purchases of crude oil and products | 360 |
| | 328 |
| | 992 |
| | 818 |
|
Production, operating and transportation expenses | 57 |
| | 52 |
| | 163 |
| | 144 |
|
Selling, general and administrative expenses | 7 |
| | 2 |
| | 12 |
| | 6 |
|
Depletion, depreciation, amortization and impairment | 29 |
| | 30 |
| | 86 |
| | 87 |
|
Financial items | 1 |
| | 1 |
| | 1 |
| | 1 |
|
Provisions for income taxes | 3 |
| | 33 |
| | 18 |
| | 106 |
|
Net earnings | 7 |
| | 88 |
| | 49 |
| | 281 |
|
Upgrading throughput (mbbls/day)(1) | 75.6 |
| | 77.2 |
| | 73.4 |
| | 76.9 |
|
Total sales (mbbls/day) | 75.3 |
| | 76.7 |
| | 74.3 |
| | 75.1 |
|
Synthetic crude oil sales (mbbls/day) | 58.5 |
| | 54.9 |
| | 55.4 |
| | 52.6 |
|
Upgrading differential ($/bbl) | 17.22 |
| | 29.46 |
| | 15.65 |
| | 29.38 |
|
Unit margin ($/bbl) | 15.01 |
| | 29.19 |
| | 16.22 |
| | 30.48 |
|
Unit operating cost ($/bbl)(2) | 8.20 |
| | 7.32 |
| | 8.13 |
| | 6.86 |
|
| |
(1) | Throughput includes diluent returned to the field. |
Third Quarter
Upgrading gross revenues decreased by $70 million in the third quarter of 2019 compared to the third quarter of 2018, primarily due to lower realized prices for synthetic crude oil, partially offset by higher synthetic crude sales volumes. The price of Husky Synthetic Blend in the third quarter of 2019 averaged $74.80/bbl compared to $88.94/bbl in the third quarter of 2018.
Upgrading purchases of crude oil and products increased by $32 million in the third quarter of 2019 compared to the third quarter of 2018, primarily due to an increase in the average cost of heavy crude oil feedstock, partially offset by lower throughput volumes in third quarter of 2019.
Provisions for income taxes decreased by $30 million in the third quarter of 2019 compared to the third quarter of 2018, primarily due to lower earnings before income taxes in the third quarter of 2019.
Nine Months
Upgrading gross revenues decreased by $122 million compared to the same period in 2018, primarily due to lower realized prices for synthetic crude oil, partially offset by higher synthetic crude sales volumes. The price of Husky Synthetic Blend averaged $74.67/bbl compared to $84.16/bbl in the same period in 2018.
Upgrading purchases of crude oil and products increased by $174 million compared to the same period in 2018, primarily due to an increase in the average cost of heavy crude oil feedstock, partially offset by lower throughput volumes in 2019.
Provisions for income taxes decreased by $88 million compared to the same period in 2018, primarily due to the same factors which impacted the third quarter.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 17
Canadian Refined Products
|
| | | | | | | | | | | |
Canadian Refined Products Earnings Summary | Three months ended September 30, | | | Nine months ended September 30, | |
($ millions, except where indicated) | 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
Gross revenues | 871 |
| | 1,001 |
| | 2,329 |
| | 2,591 |
|
Expenses | | | | | | | |
Purchases of crude oil and products | 706 |
| | 834 |
| | 1,880 |
| | 2,123 |
|
Production, operating and transportation expenses | 69 |
| | 66 |
| | 221 |
| | 198 |
|
Selling, general and administrative expenses | 13 |
| | 12 |
| | 40 |
| | 36 |
|
Depletion, depreciation, amortization and impairment | 32 |
| | 29 |
| | 99 |
| | 86 |
|
Gain on sale of assets | (4 | ) | | (2 | ) | | (4 | ) | | (2 | ) |
Financial items | 4 |
| | 3 |
| | 12 |
| | 9 |
|
Provisions for income taxes | 14 |
| | 16 |
| | 22 |
| | 38 |
|
Net earnings | 37 |
| | 43 |
| | 59 |
| | 103 |
|
Number of fuel outlets(1) | 555 |
| | 558 |
| | 554 |
| | 558 |
|
Fuel sales volume, including wholesale | | | | | | | |
Fuel sales (millions of litres/day) | 7.5 |
| | 7.7 |
| | 7.4 |
| | 7.5 |
|
Fuel sales per retail outlet (thousands of litres/day) | 13.5 |
| | 12.4 |
| | 12.4 |
| | 12.1 |
|
Refinery throughput | | | | | | | |
Prince George Refinery (mbbls/day)(2) | 11.4 |
| | 11.5 |
| | 8.4 |
| | 10.7 |
|
Lloydminster Refinery (mbbls/day)(2) | 28.3 |
| | 27.8 |
| | 25.8 |
| | 27.8 |
|
Ethanol production (thousands of litres/day) | 798.9 |
| | 772.3 |
| | 816.5 |
| | 800.9 |
|
| |
(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 decreased by $130 million in the third quarter of 2019 compared to the third quarter of 2018, primarily due to lower product prices.
Canadian Refined Products purchases of crude oil and products decreased by $128 million in the third quarter of 2019 compared to the third quarter of 2018, primarily due to lower commodity prices.
Nine Months
Canadian Refined Products gross revenues decreased by $262 million compared to the same period in 2018, primarily due to lower sales volumes, combined with the same factors which impacted the third quarter.
Canadian Refined Products purchases of crude oil and products decreased by $243 million compared to the same period in 2018, primarily due to lower throughput volumes resulting primarily from a planned turnaround at the Prince George Refinery in the second quarter of 2019, combined with the same factors which impacted the third quarter.
Canadian Refined Products production, operating and transportation expenses increased by $23 million compared to the same period in 2018, primarily due to costs related to a planned turnaround at the Prince George Refinery in the second quarter of 2019.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 18
U.S. Refining and Marketing
|
| | | | | | | | | | | |
U.S. Refining and Marketing Earnings Summary | Three months ended September 30, | | | Nine months ended September 30, | |
($ millions, except where indicated) | 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
Gross revenues | 2,644 |
| | 3,198 |
| | 7,718 |
| | 9,004 |
|
Expenses | | | | | | | |
Purchases of crude oil and products | 2,319 |
| | 2,741 |
| | 6,489 |
| | 7,811 |
|
Production, operating and transportation expenses | 197 |
| | 222 |
| | 628 |
| | 602 |
|
Selling, general and administrative expenses | 7 |
| | 5 |
| | 23 |
| | 17 |
|
Depletion, depreciation, amortization and impairment | 117 |
| | 129 |
| | 355 |
| | 348 |
|
Loss on sale of asset | 1 |
| | — |
| | 1 |
| | — |
|
Other – net | (163 | ) | | (107 | ) | | (347 | ) | | (130 | ) |
Financial items | 5 |
| | 4 |
| | 14 |
| | 11 |
|
Provisions for income taxes | 35 |
| | 46 |
| | 123 |
| | 77 |
|
Net earnings | 126 |
| | 158 |
| | 432 |
| | 268 |
|
Select operating data: | | | | | | | |
Lima Refinery throughput (mbbls/day)(1) | 174.3 |
| | 163.3 |
| | 175.2 |
| | 166.3 |
|
BP-Husky Toledo Refinery throughput (mbbls/day)(1)(2) | 66.8 |
| | 70.8 |
| | 60.6 |
| | 70.4 |
|
Superior Refinery throughput (mbbls/day)(1) | — |
| | — |
| | — |
| | 15.6 |
|
Refining and marketing margin (US$/bbl crude throughput) | 12.17 |
| | 17.52 |
| | 14.60 |
| | 13.99 |
|
Refinery inventory (mmbbls)(3) | 8.7 |
| | 9.5 |
| | 8.7 |
| | 9.5 |
|
| |
(1) | Includes all crude oil, feedstock, intermediate feedstock and blend-stocks used in producing sales volumes from the refinery. |
| |
(2) | Reported throughput volumes include Husky’s working interest from the BP-Husky Toledo Refinery (50 percent). |
| |
(3) | Feedstock and refined products are included in refinery inventory. |
Third Quarter
U.S. Refining and Marketing gross revenues decreased by $554 million in the third quarter of 2019 compared to the third quarter of 2018, primarily due to lower prices and lower sales volumes at the BP-Husky Toledo Refinery, partially offset by higher sales volumes at the Lima Refinery, which entered into a major planned turnaround late in the third quarter of 2018.
U.S. Refining and Marketing purchases of crude oil and products decreased by $422 million in the third quarter of 2019 compared to the third quarter of 2018, primarily due to lower commodity prices and lower throughput at the BP-Husky Toledo Refinery, partially offset by higher throughput at the Lima Refinery, which entered into a major planned turnaround late in the third quarter of 2018.
Production, operating and transportation expenses decreased by $25 million in the third quarter of 2019 compared to the third quarter of 2018, primarily due to costs associated with the incident at the Superior Refinery.
Other – net income increased by $56 million in the third quarter of 2019 compared to the third quarter of 2018, primarily due to pre-tax insurance recoveries for business interruption and incident costs associated with the incident at the Superior Refinery.
Nine Months
U.S. Refining and Marketing gross revenues decreased by $1,286 million compared to the same period in 2018, primarily due to lower sales volumes at the Superior Refinery, combined with the same factors which impacted the third quarter.
U.S. Refining and Marketing purchases of crude oil and products decreased by $1,322 million compared to the same period in 2018, primarily due to the realization of the lower cost crude oil feedstock, from late 2018, at the Lima Refinery during the first quarter of 2019, combined with the same factors which impacted the third quarter.
Other – net income increased by $217 million compared to the same period in 2018, primarily due to the same factors which impacted the third quarter.
Provisions for income taxes increased by $46 million compared to the same period in 2018, primarily due to higher earnings before income taxes in 2019.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 19
Downstream Capital Expenditures
During the first nine months of 2019, Downstream capital expenditures totalled $656 million compared to $474 million in the same period in 2018. In Canada, capital expenditures of $129 million related primarily to the polymer modified asphalt project at the Lloydminster Refinery and the planned turnaround at the Prince George Refinery. In the U.S., capital expenditures of $527 million related primarily to the crude oil flexibility project at the Lima Refinery and costs related to the turnaround at the BP-Husky Toledo Refinery.
4.3 Corporate
|
| | | | | | | | | | | |
Corporate Summary | Three months ended September 30, | | | Nine months ended September 30, | |
($ millions) income (expense) | 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
Production, operating and transportation expenses | 1 |
| | — |
| | 2 |
| | — |
|
Selling, general and administrative expenses | (44 | ) | | (96 | ) | | (173 | ) | | (256 | ) |
Depletion, depreciation and amortization | (24 | ) | | (23 | ) | | (77 | ) | | (65 | ) |
Other – net | 22 |
| | — |
| | 12 |
| | 9 |
|
Net foreign exchange gain (loss) | (8 | ) | | (9 | ) | | 24 |
| | 16 |
|
Finance income | 24 |
| | 13 |
| | 60 |
| | 36 |
|
Finance expense | (33 | ) | | (43 | ) | | (122 | ) | | (137 | ) |
Recovery of income taxes | 25 |
| | 51 |
| | 328 |
| | 116 |
|
Net earnings (loss) | (37 | ) | | (107 | ) | | 54 |
| | (281 | ) |
Third Quarter
The Corporate segment reported a net loss of $37 million in the third quarter of 2019 compared to a net loss of $107 million in the third quarter of 2018. Selling, general and administrative expenses decreased by $52 million primarily due to lower stock-based compensation expenses. Other – net income increased by $22 million, primarily due to an unrealized gain on short-dated foreign exchange forwards, combined with a net realized and unrealized gain on the Company's commodity short-term hedging program. Recovery of income taxes decreased by $26 million, primarily due to the factors discussed in the Consolidated Income Taxes section below.
Nine Months
In the first nine months of 2019, the Corporate segment reported net earnings of $54 million compared to a net loss of $281 million in the same period in 2018. Selling, general and administrative expenses decreased by $83 million, primarily due to lower stock-based compensation expenses. Recovery of income taxes increased by $212 million, primarily due to the factors discussed in the Consolidated Income Taxes section below.
The net foreign exchange gain increased by $8 million due to items noted below.
|
| | | | | | | | | | | |
Foreign Exchange Summary | Three months ended September 30, | | | Nine months ended September 30, | |
($ millions, except where indicated) | 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
Non-cash working capital gain (loss) | 16 |
| | (12 | ) | | (15 | ) | | (12 | ) |
Other foreign exchange gain (loss) | (24 | ) | | 3 |
| | 39 |
| | 28 |
|
Net foreign exchange gain (loss) | (8 | ) | | (9 | ) | | 24 |
| | 16 |
|
U.S./Canadian dollar exchange rates: | | | | | | | |
At beginning of period | US$0.764 |
| | US$0.761 |
| | US$0.733 |
| | US$0.799 |
|
At end of period | US$0.755 |
| | US$0.774 |
| | US$0.755 |
| | US$0.774 |
|
Included in the other foreign exchange gain (loss) are realized and unrealized gains and losses on working capital and intercompany financing. The foreign exchange gains and losses on these items can vary significantly due to the large volume and timing of transactions through these accounts in the period. The Company manages its exposure to foreign currency fluctuations with the goal of minimizing the impact of foreign exchange gains and losses on the condensed interim consolidated financial statements.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 20
Consolidated Income Taxes
|
| | | | | | | | | | | |
Consolidated Income Taxes | Three months ended September 30, | | | Nine months ended September 30, | |
($ millions) | 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
Provisions for (recovery of) income taxes | 73 |
| | 169 |
| | (42 | ) | | 420 |
|
Cash income taxes paid (received) | (44 | ) | | (70 | ) | | 34 |
| | (10 | ) |
Third Quarter
Consolidated income taxes were a provision of $73 million in the third quarter of 2019 compared to a provision of $169 million in the third quarter of 2018. The decrease in consolidated income taxes was primarily due to lower earnings before income taxes in the third quarter of 2019.
Nine Months
Consolidated income taxes were a recovery of $42 million compared to a provision of $420 million in the same period in 2018. The decrease in consolidated income taxes was primarily due to the recognition of $233 million in tax recoveries related to the reduction in the Alberta provincial corporate tax rate that was substantively enacted in the second quarter of 2019, combined with 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 February 26, 2019. 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, which were discussed in the Company’s MD&A for the year ended December 31, 2018, have not materially changed since December 31, 2018.
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, 2019, 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 15 of the condensed interim consolidated financial statements.
During the nine months ended September 30, 2019, the Company entered into a commodity short-term hedging program using put and call options to manage risks related to volatility of commodity prices.
|
| | | | | | | | |
WTI Crude Oil Call and Put Option Contracts(1) | | |
Type | Transaction | Term | Volume (bbls/day) |
| Call Price (US$bbl) |
| Put Price (US$bbl) |
|
Call options | Sold | October - December 2019 | 17,935 |
| 59.35 |
| — |
|
Put options | Bought | October - December 2019 | 23,641 |
| — |
| 55.16 |
|
Put options | Sold | October - December 2019 | 22,283 |
| — |
| 50.40 |
|
| |
(1) | Prices reported are the weighted average prices for the period. |
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 21
Foreign Exchange Risk Management
At September 30, 2019, Cdn $4.2 billion or 69 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. As at September 30, 2019, Cdn $3.2 billion of the Company’s total outstanding long-term debt 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, 2019, the Company incurred an unrealized loss of $32 million and an unrealized gain of $91 million, respectively, arising from the translation of the debt, net of tax recovery of $5 million and net of tax of $12 million, respectively, which was recorded in hedge of net investment within other comprehensive income (loss).
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.
At September 30, 2019, the Company had the following available credit facilities:
|
| | | | | |
Credit Facilities | | | |
($ millions) | Available |
| | Unused |
|
Operating facilities(1) | 900 |
| | 470 |
|
Syndicated credit facilities(2) | 4,000 |
| | 3,800 |
|
Total | 4,900 |
| | 4,270 |
|
| |
(1) | Consists of demand credit facilities. |
| |
(2) | Commercial paper outstanding is supported by the Company’s syndicated credit facilities. |
At September 30, 2019, the Company had $4,270 million of unused credit facilities of which $3,800 million are long-term committed credit facilities and $470 million are short-term uncommitted credit facilities. A total of $430 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, 2019, the Company had no direct borrowing against committed credit facilities. The maturity dates for the Company's revolving syndicated credit facilities are June 19, 2022 and March 9, 2024. 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.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 22
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, 2019, 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, 2019, working capital was $672 million compared to $694 million at December 31, 2018.
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, 2019.
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. 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.
On March 15, 2019, the Company issued US$750 million senior unsecured notes. The notes bear an annual interest rate of 4.40 percent and are due on April 15, 2029. The Company intends to use the net proceeds of the offering for general corporate purposes, which may include, among other things, the repayment of certain outstanding debt securities maturing in 2019. The Company may invest funds it does not immediately require in short-term marketable debt securities.
On May 1, 2019, the Company filed a universal short form base shelf prospectus (the "2019 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 June 1, 2021. The 2019 Canadian Shelf Prospectus replaced the Company's Canadian universal short form base shelf prospectus which expired on April 30, 2019. During the 25-month period that the 2019 Canadian Shelf Prospectus is in effect, securities may be offered in amounts, at prices and on terms set forth in a prospectus supplement.
On June 17, 2019, the Company repaid the maturing 6.15 percent notes. The amount paid to note holders was $402 million.
On June 27, 2019, the maturity date for one of the Company's $2.0 billion revolving syndicated credit facilities, previously set to expire on March 9, 2020, was extended to March 9, 2024.
As at September 30, 2019, the Company had $3.0 billion in unused capacity under the 2019 Canadian Shelf Prospectus and US$2.25 billion in unused capacity under the 2018 U.S. Shelf Prospectus and related U.S. registration statement. The ability of the Company to utilize the capacity under the 2019 Canadian Shelf Prospectus and the 2018 U.S. Shelf Prospectus and related U.S. registration statement is subject to market conditions at the time of sale.
6.2 Capital Structure
|
| | |
Capital Structure | September 30, 2019 |
|
($ millions) | Outstanding |
|
Total debt(1) | 6,228 |
|
Shareholders' equity | 19,935 |
|
| |
(1) | Total debt is a non-GAAP measure. Refer to Section 10.3 for a reconciliation to the corresponding GAAP measure. |
The Company considers its capital structure to include shareholders’ equity and debt which totalled $26.2 billion as at September 30, 2019 (December 31, 2018 – $25.4 billion). To maintain or adjust the capital structure, the Company may, from time to time, 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 trailing 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 trailing funds from operations ratio of less than 2.0 times. At September 30, 2019, debt to capital employed was 23.8 percent (December 31, 2018 – 22.7 percent) and debt to trailing funds from operations was 1.9 times (December 31, 2018 – 1.4 times).
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 23
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, 2018 under the caption “Liquidity and Capital Resources” which summarizes contractual obligations and other commercial commitments as at December 31, 2018. During the three months ended September 30, 2019, 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.
6.4 Transactions with Related Parties
The Company performs management services as the operator of the assets held by HMLP for which it recovers shared service costs. 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 Cheung Kong Infrastructure Holdings Limited, which are affiliates of one of the Company’s principal shareholders. For the three and nine months ended September 30, 2019, the Company charged HMLP $108 million and $304 million, respectively, related to construction and management services. For the three and nine months ended September 30, 2019, the Company had purchases from HMLP of $51 million and $160 million, respectively, related to the use of the pipeline for the Company’s blending, transportation and storage activities. As at September 30, 2019, the Company had $143 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, 2018, 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.
Changes in Accounting Policies
Leases
In January 2016, the IASB issued IFRS 16 Leases (“IFRS 16”), which replaces the existing IFRS guidance on leases: IAS 17 Leases (“IAS 17”). Under IAS 17, lessees were required to determine if the lease is a finance or operating lease, based on specified criteria of whether the lease transferred significantly all the risks and rewards associated with ownership of the underlying asset. 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 most lease contracts. The recognition of the present value of minimum lease payments for certain contracts previously classified as operating leases resulted in increases to assets, liabilities, depletion, depreciation and amortization, and finance expense, and decreases to production, operating and transportation expense, purchases of crude oil and products, and selling, general and administrative expenses.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 24
The Company has adopted IFRS 16 on January 1, 2019 using the modified retrospective approach. The modified retrospective approach does not require restatement of prior period financial information as it recognizes the cumulative effect as an adjustment to opening retained earnings and applies the standard prospectively. Accordingly, comparative information in the Company’s financial statements are not restated.
On adoption, lease liabilities were measured at the present value of the remaining lease payments discounted using the Company’s incremental borrowing rate on January 1, 2019. Right-of-use assets were measured at an amount equal to the lease liability. For leases previously classified as operating leases, the Company applied the exemption not to recognize right-of-use assets and liabilities for leases with a lease term of less than 12 months, excluded initial direct costs from measuring the right-of-use asset at the date of initial application, and applied a single discount rate to a portfolio of leases with similar characteristics. For leases that were previously classified as finance leases under IAS 17, the carrying amount of the right-of-use asset and lease liability remain unchanged upon transition and were determined at the carrying amount immediately before the adoption date. Additionally, instead of an impairment review, the Company adjusted the right-of-use assets by the amount of IAS 37 onerous contract provision immediately before the date of initial application.
No adjustments were required upon transition to IFRS 16 for leases where the Company is a lessor. Under IFRS 16, the Company is required to assess the classification of a sub-lease with reference to the right-of-use asset, not the underlying asset. On transition, the Company reassessed the classification of any sub-lease contracts previously assessed under IAS 17. No changes to sublease classification or associated accounting treatment was required.
The nature of the Company’s leasing activities includes offshore drilling rigs, vessels and associated equipment for the use of developing reserves on oil and gas properties, tanks and terminals with dedicated storage capacity, pipelines where the Company has a right to substantially all the economic benefits, dedicated rail cars, retail marketing locations, and office space.
9.0 Outstanding Share Data
Authorized:
| |
• | unlimited number of common shares |
| |
• | unlimited number of preferred shares |
Issued and outstanding: October 21, 2019:
| |
• | common shares 1,005,121,738 |
| |
• | 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 19,500,839 |
| |
• | stock options exercisable 10,658,921 |
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 2019 production guidance, including guidance for specified areas and product types; the intended use of proceeds of the US$750 million senior unsecured notes offering; and the Company’s objective of maintaining stated debt to trailing funds from operations and debt to capital employed ratio targets; |
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 25
| |
• | with respect to the Company's thermal developments: the expected timing of first production at the Spruce Lake Central, Spruce Lake North, Spruce Lake East, Edam Central and Dee Valley 2 projects; and the expected timing of completion of the Central Processing Facility at Spruce Lake Central; |
| |
• | with respect to the Company’s Western Canada resource plays, the expected timing of production at 10 Montney wells at Wembley and Karr; |
| |
• | with respect to the Company's Offshore business in Asia Pacific: the expected timing of installation of the upper completion of the remaining four wells, and of the control system and flow lines, at Liuhua 29-1; the expected timing of first gas production at Liuhua 29-1; the expected timing of gas production and sales from the MDA and MBH fields; and development plans for the additional MDK shallow water field; |
| |
• | with respect to the Company's Offshore business in the Atlantic, the expected timing of first production at the West White Rose Project; |
| |
• | with respect to the Company’s Infrastructure and Marketing business: expansion plans for the Saskatchewan Gathering System; the processing capacity expected to be added by the Ansell Corser Gas Plant when it comes online, and the expected timing thereof; and the expected timing of completion of construction of additional storage at the Hardisty Terminal; and |
| |
• | with respect to the Company's Downstream operating segment: plans to market and potentially sell the Canadian retail and commercial fuels business; the contingent payment of up to $60 million as part of the consideration for, and the expected closing date of, the sale of the Prince George Refinery; the expected timing of completion of the crude oil flexibility project at the Lima Refinery; the expected investment in the rebuild of the Superior Refinery and anticipated insurance recoveries associated therewith; and the expected timing of resumption of full 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, including the timing of regulatory approvals, that may prove to be inaccurate. Those assumptions and factors are based on information currently available to the Company about itself and the businesses in which it operates. Information used in developing forward-looking statements has been acquired from various sources, including third party consultants, suppliers and regulators, among others.
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, 2018 and other documents filed with securities regulatory authorities (accessible through the SEDAR website www.sedar.com and the EDGAR website www.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.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 26
10.2 Cautionary Note Required by National Instrument 51-101
Unless otherwise noted: (i) projected and historical production volumes disclosed are gross, which represents, as applicable, the total or the Company’s working interest share before deduction of royalties; and (ii) all Husky working interest production volumes disclosed are before deduction of 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 funds from operations, total debt, debt to capital employed, debt to trailing funds from operations and sustaining capital. None of these measures is 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 trailing funds from operations. These are useful complementary measures that are used by management in assessing the Company’s financial performance, efficiency and liquidity, and they may be used by the Company's investors for the same purpose. The non-GAAP measures do not have standardized meanings 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.
Debt to Capital Employed
Debt to capital employed percentage is a non-GAAP measure and is equal to total debt divided by capital employed. Capital employed is equal to total debt and shareholders’ equity. Management believes this measure assists management and investors in evaluating the Company’s financial strength.
Debt to Trailing Funds from Operations
Debt to trailing funds from operations is a non-GAAP measure and is equal to total debt divided by the 12-month trailing funds from operations as at September 30, 2019. Trailing funds from operations is equal to cash flow – operating activities excluding change in non-cash working capital annualized using 12-month rolling figures. Management believes this measure assists management and investors in evaluating the Company’s financial strength.
The following table shows the reconciliation of debt to trailing funds from operations for the periods ended September 30, 2019, and December 31, 2018:
|
| | | | | |
Debt to Trailing Funds from Operations | | | |
($ millions) | September 30, 2019 |
| | December 31, 2018 |
|
Total debt | 6,228 |
| | 5,747 |
|
Trailing funds from operations | 3,365 |
| | 4,004 |
|
Debt to trailing funds from operations | 1.9 |
| | 1.4 |
|
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 27
Funds from Operations
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 equals cash flow – operating activities excluding change in non-cash working capital. Management believes that impacts of non-cash working capital items on cash flow – operating activities may reduce comparability between periods, accordingly, funds from operations is presented in the Company’s financial reports to assist management and investors in analyzing operating performance of the Company in the stated period compared to prior periods.
The following table shows the reconciliation of net earnings to funds from operations and related per share amounts for the periods ended: |
| | | | | | | | | | | | | | | | |
Reconciliation of Cash Flow | Three months ended |
| Sept. 30 |
| Jun. 30 |
| Mar. 31 |
| Dec. 31 |
| Sept. 30 |
| Jun. 30 |
| Mar. 31 |
| Dec. 31 |
|
($ millions) | 2019 |
| 2019 |
| 2019 |
| 2018 |
| 2018 |
| 2018 |
| 2018 |
| 2017 |
|
Net earnings | 273 |
| 370 |
| 328 |
| 216 |
| 545 |
| 448 |
| 248 |
| 672 |
|
Items not affecting cash: | | | | | | | | |
Accretion | 26 |
| 26 |
| 27 |
| 25 |
| 23 |
| 25 |
| 24 |
| 28 |
|
Depletion, depreciation, amortization and impairment | 703 |
| 643 |
| 630 |
| 662 |
| 672 |
| 639 |
| 618 |
| 647 |
|
Inventory write-down to net realizable value | — |
| — |
| — |
| 60 |
| — |
| — |
| — |
| — |
|
Exploration and evaluation expenses | — |
| 23 |
| — |
| 22 |
| — |
| 7 |
| — |
| — |
|
Deferred income taxes | 22 |
| (250 | ) | 43 |
| 25 |
| 156 |
| 138 |
| 77 |
| (360 | ) |
Foreign exchange loss (gain) | (1 | ) | (2 | ) | (12 | ) | 1 |
| (6 | ) | (2 | ) | 1 |
| 1 |
|
Stock-based compensation | (9 | ) | 13 |
| 7 |
| (50 | ) | 40 |
| 33 |
| 21 |
| 25 |
|
Gain on sale of assets | (3 | ) | — |
| (2 | ) | — |
| — |
| — |
| (4 | ) | (13 | ) |
Unrealized mark to market loss (gain) | 4 |
| (4 | ) | 57 |
| (16 | ) | (22 | ) | (26 | ) | (86 | ) | 57 |
|
Share of equity investment gain | (19 | ) | (23 | ) | (22 | ) | (16 | ) | (18 | ) | (26 | ) | (9 | ) | (1 | ) |
Gain on insurance recoveries for damage to property | (13 | ) | — |
| — |
| (253 | ) | — |
| — |
| — |
| — |
|
Other | 5 |
| 5 |
| (9 | ) | 2 |
| (2 | ) | 19 |
| 2 |
| 8 |
|
Settlement of asset retirement obligations | (73 | ) | (41 | ) | (72 | ) | (65 | ) | (45 | ) | (22 | ) | (49 | ) | (45 | ) |
Deferred revenue | (7 | ) | (5 | ) | (16 | ) | (30 | ) | (25 | ) | (25 | ) | (20 | ) | (5 | ) |
Distribution from equity investment | 113 |
| 47 |
| — |
| — |
| — |
| — |
| 72 |
| — |
|
Change in non-cash working capital | (221 | ) | (42 | ) | (414 | ) | 730 |
| (35 | ) | (199 | ) | (366 | ) | 337 |
|
Cash flow – operating activities | 800 |
| 760 |
| 545 |
| 1,313 |
| 1,283 |
| 1,009 |
| 529 |
| 1,351 |
|
Change in non-cash working capital | 221 |
| 42 |
| 414 |
| (730 | ) | 35 |
| 199 |
| 366 |
| (337 | ) |
Funds from operations | 1,021 |
| 802 |
| 959 |
| 583 |
| 1,318 |
| 1,208 |
| 895 |
| 1,014 |
|
Funds from operations – basic | 1.02 |
| 0.80 |
| 0.95 |
| 0.58 |
| 1.31 |
| 1.20 |
| 0.89 |
| 1.01 |
|
Funds from operations – diluted | 1.02 |
| 0.80 |
| 0.95 |
| 0.58 |
| 1.31 |
| 1.20 |
| 0.89 |
| 1.01 |
|
Total debt
Total debt is a non-GAAP measure that equals the sum of long-term debt, long-term debt due within one year and short-term debt. Management believes this measure assists management and investors in evaluating the Company’s financial strength.
The following table shows the reconciliation of total debt for the periods ended September 30, 2019 and December 31, 2018:
|
| | | | | |
Total Debt | | | |
($ millions) | September 30, 2019 |
| | December 31, 2018 |
|
Short-term debt | 200 |
| | 200 |
|
Long-term debt due within one year | 1,393 |
| | 1,433 |
|
Long-term debt | 4,635 |
| | 4,114 |
|
Total debt | 6,228 |
| | 5,747 |
|
Sustaining Capital
Sustaining capital is the additional development capital that is required by the business to maintain production and operations at existing levels. Development capital includes the cost to drill, complete, equip and tie-in wells to existing infrastructure. Sustaining capital does not have any standardized meaning and therefore should not be used to make comparisons to similar measures presented by other issuers.
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 28
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, 2018, the 2018 consolidated financial statements, the Annual Information Form dated February 26, 2019 filed with Canadian securities regulatory authorities and the 2018 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.
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, 2019 and the nine months ended September 30, 2019 are compared to the results for the three months ended September 30, 2018 and the nine months ended September 30, 2018. Discussions with respect to the Company’s financial position as at September 30, 2019 are compared to its financial position as at December 31, 2018. 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. |
| |
• | 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, 2019 that have materially affected, or are reasonably likely to affect, the Company’s ICFR. |
HUSKY ENERGY INC. | Q3 | Management's Discussion and Analysis | 29
|
| | |
Terms |
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 | | Bitumen is 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 trailing funds from operations | | Long-term debt, long-term debt due within one year and short-term debt divided by trailing 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 excluding change in non-cash working capital |
Gross/net wells | | Gross refers to the total number of 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 |
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 revenue | | Gross revenues 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 mineral substances in association therewith |
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 test well | | A geologically directed test well to obtain information. These wells are usually drilled without the intention of being completed for production |
Sustaining capital | | The additional development capital that is required by the business to maintain production and operations at existing levels. Development capital includes the cost to drill, complete, equip and tie-in wells to existing infrastructure. |
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 |
|
| | | | |
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 | 30
