Husky Energy (CVE+A) 6-K Husky Energy Reports First Quarter 2020 Results

MANAGEMENT’S DISCUSSION AND ANALYSIS

April 29, 2020

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	Mar. 31		Dec. 31		Sept. 30	Jun. 30	Mar. 31	Dec. 31	Sept. 30	Jun. 30
($ millions, except where indicated)	2020		2019		2019	2019	2019	2018(2)	2018(2)	2018(2)
Production (mboe/day)	298.9		311.3		294.8	268.4	285.2	304.3	296.7	295.5
Throughput (mbbls/day)	307.8		203.4		356.4	340.3	333.6	286.9	350.6	354.9
Gross revenues and Marketing and other	4,113		4,921		5,373	5,321	4,610	5,042	6,300	5,983
Net earnings (loss)	(1,705	)	(2,341	)	273	370	328	216	545	448
Per share – Basic	(1.71	)	(2.34	)	0.26	0.36	0.32	0.21	0.53	0.44
Per share – Diluted	(1.71	)	(2.34	)	0.25	0.36	0.31	0.16	0.53	0.44
Cash flow – operating activities	355		866		800	760	545	1,313	1,283	1,009
Funds from operations(1)	25		469		1,021	802	959	583	1,318	1,208
Per share – Basic	0.02		0.47		1.02	0.80	0.95	0.58	1.31	1.20
Per share – Diluted	0.02		0.47		1.02	0.80	0.95	0.58	1.31	1.20

⁽¹⁾  Funds from operations is a non-GAAP measure. Refer to Section 10.3 for a reconciliation to the corresponding GAAP measure.

⁽²⁾  Gross revenues and Marketing and other results reported for 2019 have been recast to reflect a change in reclassification of intersegment sales eliminations and a change in presentation of the Integrated Corridor and Offshore business units. The results for 2018 have not been recast for this change.

Financial Performance

• Net loss of $1,705 million in the first quarter of 2020 compared to net earnings of $328 million in the first quarter of 2019, with the decrease primarily due to:

• The recognition of an after-tax impairment of $1,053 million, in the Oil Sands and Western Canada Production segments within the Integrated Corridor business and the Atlantic segment within the Offshore business, due to the market impact from the COVID-19 pandemic, which has resulted in declines in current and forecasted crude oil prices and management's decision to delay capital investment in the West White Rose Project;

• The recognition of an after-tax inventory impairment of $274 million as a result of declining market benchmark prices;

• Lower earnings from U.S. Refining due to the lower refining margins as a result of the significant decline in global commodity prices in the first quarter of 2020; and

• Lower earnings from U.S. Refining due to the delayed startup of the crude oil flexibility project at the Lima Refinery, resulting in lower sales volumes. 

• Cash flow – operating activities and funds from operations, which excludes changes in working capital, were $355 million and $25 million, respectively, in the first quarter of 2020 compared to $545 million and $959 million, respectively, in the first quarter of 2019, with the decrease primarily attributed to the significant decline in global commodity prices in the first quarter of 2020.

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Operational Performance

• Production increased by 13.7 mboe/day, or 5%, to 298.9 mboe/day in the first quarter of 2020 compared to the first quarter of 2019 primarily due to:

• Higher production from the White Rose field, which resumed full production in mid-August 2019; and

• Higher bitumen production from the Company's Sunrise and Lloydminster thermal projects.

Partially offset by:

• Lower natural gas and natural gas liquids (“NGL”) production from Western Canada; and

• Lower production from the Terra Nova field due to suspended operations.

• Throughput decreased by 25.8 mbbls/day, or 8%, to 307.8 mbbls/day in the first quarter of 2020 compared to the first quarter of 2019 primarily due to:

• Lower throughput from the Lima Refinery due to the extended startup of the crude oil flexibility project and management's decision to reduce refinery operating rates due to reduced product demand; and

• Lower throughput from Canadian refining operations due to the sale of the Prince George Refinery in the fourth quarter of 2019.

Partially offset by:

• Higher throughput from the BP-Husky Toledo Refinery and the Lloydminster Heavy Oil Value Chain.

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 Integrated Corridor and Offshore business units (as such terms are defined below).

2.1        Corporate Strategy

The Company’s business strategy is to generate returns from 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”) and with Atlantic, collectively (“Offshore”). These projects and 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 (i) the Lloydminster Heavy Oil Value Chain; (ii) Oil Sands; (iii) Western Canada Production; (iv) U.S. Refining; and (v) Canadian Refined Products.

The Lloydminster Heavy Oil Value Chain includes the exploration for, and development and production of, heavy crude oil and bitumen, and production of ethanol. Blended heavy crude oil and bitumen are either sold directly to the Canadian market or transported utilizing the Husky Midstream Limited Partnership ("HMLP") pipeline systems to the Keystone pipeline and other pipelines to be sold in the U.S. downstream market. Heavy crude oil can be upgraded at the Company’s Lloydminster upgrading and asphalt refining complex into synthetic crude oil and diesel fuel or used to produce asphalt. This business also includes the marketing and transportation of both the Company’s own production and third party commodity trading volumes of heavy crude oil, synthetic crude oil, asphalt and ancillary products. The sale and transportation of the Company’s production and third party commodity trading volumes are managed through access to capacity on third party pipelines and storage facilities in both Canada and the U.S. The Company is able to capture price differences between the two markets by utilizing infrastructure capacity to deliver production and/or third party commodity trading volumes from Canada to the U.S. market.

The Oil Sands business includes the exploration for, and development and production of, bitumen within the Sunrise Energy Project.  It also includes the marketing and transportation of the Company’s and third party production of bitumen through access to capacity on third party pipelines and storage facilities in both Canada and the U.S.

The Western Canada Production (“WCP”) business includes the exploration for, and development and production of, light crude oil, conventional natural gas and NGL in western Canada. The Company’s conventional natural gas production is used by the Company for its own midstream facilities, and both its produced conventional natural gas and NGL are marketed and transported with other third party commodity trading volumes through access to capacity on third party pipelines, export terminals and storage facilities which provides flexibility for market access.

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The U.S. Refining business includes the refining of crude oil at the Lima Refinery, the BP-Husky Toledo Refinery and the Superior Refinery in the U.S. Midwest to produce diesel fuel, gasoline, jet fuel, asphalt and other products. The Company also markets its own and third party volumes of refined petroleum products including gasoline and diesel fuel.

The Canadian Refined Products business includes the marketing of its own and third party volumes of refined petroleum products, including gasoline and diesel, through petroleum outlets.

Offshore

The Company’s Offshore business includes operations, development and exploration in Asia Pacific and Atlantic. The price received for Asia Pacific production is largely based on long-term contracts and crude oil production from Atlantic is primarily driven by the price of Brent.

2.2        Operations Overview and Q1 Highlights

Integrated Corridor Operations

Lloydminster Heavy Oil Value Chain

Thermal Developments

Total thermal bitumen production for the Lloydminster Heavy Oil Value Chain, including Lloydminster thermal projects and the Tucker Thermal Project, averaged 111,000 bbls/day in the first quarter of 2020, with 22,400 bbls/day at the Tucker Thermal Project. Production was impacted by a deliberate ramp down late in the quarter in response to market conditions.

The Company has an inventory of five sanctioned 10,000-barrel-per-day Saskatchewan thermal projects. These long-life developments are being built with modular, repeatable designs and require low sustaining capital once brought online. Late in the first quarter of 2020, market conditions changed materially due to both the COVID-19 pandemic and falling commodity prices. Given the flexible nature of these projects, the Company is prioritizing free cash flow and has ramped down activity on all future thermal projects, with the exception of the near-term Spruce Lake Central project. Construction activity can be ramped up once market conditions become more favourable.

Lloydminster Thermal Bitumen Projects

The following table shows the major projects and their status as at March 31, 2020:

Project Name	Nameplate Capacity (bbls/day)	Expected Project Production Date	Project Status
Spruce Lake Central	10,000	TBD	Central Processing Facility (“CPF”) construction is completeand facility has been energized. Commissioning is underway. Drilling is complete and well pads and flowlines are 85% complete. Steaming and first oil will start once economic conditions warrant.
Spruce Lake North	10,000	TBD	CPF is 74% complete. CPF construction has been placed on hold. Overall project is 64% complete.
Spruce Lake East	10,000	TBD	CPF construction and module fabrication has been suspended. Well pads and drilling are on hold.
Edam Central	10,000	TBD	Project sanctioned, and regulatory approvals have been received. Project is now on hold.
Dee Valley 2	10,000	TBD	Project sanctioned, and regulatory approvals have been received. Project is now on hold.

Cold Heavy Oil Production

Total cold heavy crude oil production averaged 30,400 bbls/day in the first quarter of 2020. Production was impacted by a deliberate ramp down late in the quarter in response to market conditions.

Upgrading

Total throughput for the Lloydminster Upgrader averaged 77,500 bbls/day. The routine maintenance turnaround scheduled for April through May has been postponed until late in the third quarter of 2020, due to measures taken to protect workers from the potential spread of COVID-19.

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Husky Midstream Limited Partnership

Saskatchewan Gathering System Expansion

A multi-year expansion program to provide transportation of diluent and heavy oil blend for several thermal plants is temporarily suspended pending further development of additional plants.

Hardisty Tanks

Construction is underway for 1.5 mmbbls of storage at the Hardisty Terminal and is scheduled for completion by the end of 2020.

Oil Sands

At the Sunrise Energy Project, total production averaged 54,000 bbls/day (27,000 bbls/day Husky working interest) in the first quarter of 2020. Production was impacted by a deliberate ramp down late in the quarter in response to market conditions. A planned second quarter turnaround at Plant 1B has been deferred to 2021.

Western Canada Production

Total production in the first quarter of 2020 averaged 62,600 boe/day. Production was impacted by the deliberate shut-in of uneconomic production late in the quarter in response to market conditions. As a result of the current business environment, no development activity is planned for the balance of 2020; however, activity can be ramped up as conditions dictate.

U.S. Refining

Lima Refinery

Total throughput for the Lima Refinery averaged 131,400 bbls/day. The crude oil flexibility project at the Lima Refinery was commissioned during the first quarter of 2020 and 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.

Superior Refinery

On April 26, 2018, the Superior Refinery experienced an incident while preparing for a major turnaround and was taken out of operation. During 2019, demolition, site preparation work and permitting were completed, and the rebuild work commenced. The investment in the rebuild is estimated to be approximately US$750 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 is being rebuilt with the same configuration and with the capability to run continuously at the 45,000 barrel-per-day operating capacity, and will be able to produce a full slate of products, including asphalt, gasoline and diesel. Engineering and field construction work on the rebuild project was temporarily suspended in March 2020 due to measures taken to protect workers from the potential spread of COVID-19. The projected refinery restart timing will be updated once project work resumes.

Canadian Refined Products

The strategic review of the Company's retail and commercial fuels business has been suspended amid the COVID-19 pandemic and the current economic environment.

Offshore

Asia Pacific

China

Block 29/26

Total production from Liwan 3-1 and Liuhua 34-2 averaged 73,000 boe/day (35,800 boe/day Husky working interest) in the first quarter of 2020. Total production consisted of conventional natural gas production of 355 mmcf/day and NGL production of 13,800 bbls/day.

Construction work continued in the first quarter of 2020 at the Liuhua 29-1 development project, the third deepwater gas field to be developed as part of the Liwan Gas Project. The project is now approximately 84% complete. During the quarter, supply lines were tested and de-watered. The control system and connecting flow lines will be installed and first gas sales from the Liuhua 29-1 field are expected by the end of 2020. Husky holds a 75% net working interest in the field, and CNOOC holds the remaining 25% working interest.

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Block 15/33

The Company is progressing commercial development plans following the successful drilling and testing of the XJ34-3-2 exploration well. The block boundaries have been expanded and additional exploration and appraisal drilling is planned in 2020.

The Company is the operator of the block with a working interest of 100% during the exploration phase. In the event of a commercial discovery, CNOOC may assume a participating partnership interest of up to 51% in the block.

Blocks 22/11 and 23/07

The Company and CNOOC signed two Production Sharing Contracts (“PSCs”) for Blocks 22/11 and 23/07 in the Beibu Gulf area of the South China Sea in the first half of 2018. The Company entered into the second exploration phase of two years for Block 23/07, and committed to drill one exploration well before the end of 2021. Block 22/11 was relinquished during the first quarter of 2020.

The Company is the operator of Block 23/07 with a working interest of 100% during the exploration phase. In the event of a commercial discovery, CNOOC may assume a participating partnership interest of up to 51%.

Indonesia

Madura Strait

Total production averaged 21,300 boe/day (8,500 boe/day Husky working interest) in the first quarter of 2020. Production consisted of conventional natural gas production of 89 mmcf/day and NGL production of 6,400 bbls/day.

At the MDA and MBH fields, the two shallow water platforms have been fully installed. The contracting consortium for the Floating Production Unit ("FPU"); however, has to date been unable to contract and fabricate this vessel to process the gas. Husky and its partners are working with the Indonesian energy regulator to determine a path forward; however, a definitive solution has yet to be agreed and approved. Therefore, as a result of this delay, plans to drill the seven production wells for MDA and MBH have been deferred from 2020 to 2021 (pending regulatory approval). Once a regulatory and contractual solution for construction of the FPU is in place, completion of the vessel is anticipated in the 2022/2023 time frame which will allow for gas sales to commence under the government- approved contracts into the East Java gas market. Subsequently, an additional shallow water field, MDK, is scheduled to be developed via a separate platform and tied into the MDA and MBH infrastructure.

At the MAC field, a stand-alone gas project in the Madura Strait, tendering for engineering, procurement and construction of all required facilities was completed in the first quarter of 2020, and tendering for a FPU will be conducted during the second quarter of 2020. It is anticipated that a final investment decision to proceed with this project will be made in the third quarter of 2020, with first production of natural gas in the 2022 time frame. Husky’s share of initial gas production from this field is estimated to be 20 mmcf/day.

Anugerah

The Company previously acquired 2-D and 3-D seismic survey data on the contract area. An analysis of that data and data from offset blocks indicated that exploratory drilling would not be economic. The block was relinquished in February 2020.

Atlantic

Overall production from Atlantic averaged 19,600 boe/day in the first quarter of 2020.

White Rose Field and Satellite Extensions

In March, the Company announced the suspension of construction activities on the West White Rose Project due to impacts related to the global COVID-19 pandemic. A safe and orderly ramp down was carried out at sites in Newfoundland and Labrador and Ingleside, Texas. Engineering and some procurement activities will continue while a new schedule is developed. As of the suspension date, the project was approximately 58% complete.

Offshore Newfoundland and Labrador, the SeaRose floating production, storage and offloading ("FPSO") vessel remained in production at the White Rose field with enhanced screening provisions and physical distancing measures for site workers.

Terra Nova Field

The Company's partner is looking at other alternatives for the dry dock for the Terra Nova FPSO vessel in light of the ongoing health and safety concerns with COVID-19. Production operations have been suspended on the vessel since December 2019. Husky has a 13% working interest in the Terra Nova oil field.

Atlantic Exploration

As previously announced by its partner, the Company and its partner have decided to defer the Bay du Nord development. Husky has a 35% non-operated working interest in the field.

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2.3        Corporate Guidance

Production and Throughput

Production and Throughput Guidance

The following table shows the current and previously issued production and throughput guidance for 2020.

	Updated Guidance(1)	Previous Guidance(1)
Production & Throughput Guidance	March 12, 2020	December 2, 2019
Upstream production (mboe/day)	275 - 300	295 - 310
Downstream throughput (mbbls/day)	320 - 340	320 - 340

⁽¹⁾  Includes curtailment allowance of 5,000 bbls/day in first half of 2020

On March 12, 2020, the Company announced that it is taking a series of actions to fortify its business in response to challenging global market conditions. Given current market conditions the Company will commence the safe and orderly reduction, or shut-in, of production to address near-term negative cash margins until supply and demand is rebalanced.

On April 20, 2020, the Company announced that the Integrated Corridor production is being aligned with upgrading and refining requirements as throughput is adjusted and optimized in line with the changing market conditions. As a result, updated production and throughput guidance was not provided.

Actual Production and Throughput

The following table shows actual daily production and throughput for the three months ended March 31, 2020, and 2019.

	Actual Production & Throughput
	Three months ended March 31,
Production & Throughput	2020	2019
Canada
Light & medium crude oil(mbbls/day)	29	17
NGL (mbbls/day)	11	14
Heavy crude oil & bitumen(mbbls/day)	168	158
Conventional natural gas (mmcf/day)	279	302
Canada total(mboe/day)	255	239
Asia Pacific
NGL (mbbls/day)(1)	9	10
Conventional natural gas (mmcf/day)(1)	210	215
Asia Pacific total(mboe/day)	44	46
Total(mboe/day)	299	285
Total throughput (mbbls/day)	308	337

⁽¹⁾  Includes Husky’s working interest production from the BD Project (40%). 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 three months ended March 31, 2020 reflects higher production from the White Rose field, which resumed full production in mid-August 2019, and higher production from the Company's Sunrise and Lloydminster thermal projects. The production increase was partially offset by lower natural gas and NGL production from Western Canada and lower production from the Terra Nova field due to suspended operations.

Throughput for the three months ended March 31, 2020 reflects lower throughput from the Lima Refinery due to the extended startup of the crude oil flexibility project and management's decision to reduce refinery operating rates due to reduced product demand, and the sale of the Prince George Refinery in the fourth quarter of 2019. The throughput decrease was partially offset by higher throughput from the BP-Husky Toledo Refinery due to higher refinery mechanical availability, as refinery availability was restricted in the first quarter of 2019 due to unplanned maintenance.

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Capital Expenditures

Capital Guidance

The following table shows the current and previously issued capital guidances for 2020.

Capital Guidance(1)	Updated Guidance	Previous Guidance	Previous Guidance
($ millions)	April 20, 2020	March 12, 2020	December 2, 2019
Integrated Corridor
Upstream	475 - 525	650 - 700	1,275 - 1,350
Downstream(2)	475 - 550	475 - 550	475 - 550
	950 - 1,075	1,125 - 1,250	1,750 - 1,900
Offshore
Asia Pacific(3)	250 - 275	250 - 275	275 - 300
Atlantic	350 - 375	875 - 925	1,075 - 1,150
	600 - 650	1,125 - 1,200	1,350 - 1,450
Corporate	50 - 75	50 - 75	50 - 75
Total	1,600 - 1,800	2,300 - 2,500	3,200 - 3,400

⁽¹⁾  Excludes capitalized costs related to asset retirement obligations and capitalized interest incurred during the period.

⁽²⁾  Excludes Superior Refinery rebuild capital.

⁽³⁾  Exclude amounts related to the Husky-CNOOC Madura Ltd. joint venture, which is accounted for under the equity method for interim financial statement purposes.

On March 12, 2020, the Company announced $900 million reduction in the capital expenditure guidance issued on December 2, 2019. On April 20, 2020, the Company announced an additional $700 million reduction in capital in response to the market conditions.

Actual Capital Expenditures

The following table shows actual capital expenditures for the three months ended March 31, 2020, and 2019.

	Actual Capital Expenditures
Capital Expenditures(1)(2)	Three months ended March 31,
($ millions)	2020	2019
Integrated Corridor
Lloydminster Heavy Oil Value Chain	263	261
Oil Sands	8	10
Western Canada Production	47	96
U.S. Refining	163	129
Canadian Refined Products	2	10
	483	506
Offshore
Atlantic	77	221
Asia Pacific(3)	30	59
	107	280
Corporate	22	26
Total	612	812

⁽¹⁾  Excludes capitalized costs related to asset retirement obligations and capitalized interest incurred during the period.

⁽²⁾  Includes capital expenditures used for exploration, development and acquisitions.

⁽³⁾  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.

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Integrated Corridor Operations

Lloydminster Heavy Oil Value Chain

During the first three months of 2020, $263 million (42%) was invested in Lloydminster Heavy Oil Value Chain compared to $261 million (32%) in the same period in 2019. Capital expenditures in 2020 related primarily to construction work at the Spruce Lake Central and Spruce Lake North thermal projects, and site preparation at the Lloydminster Upgrader for the scheduled turnaround later in the year.

Oil Sands

During the first three months of 2020, $8 million (1%) was invested in Oil Sands compared to $10 million (1%) in the same period in 2019. Capital expenditures in 2020 related primarily to sustainment activities.

Western Canada Production

During the first three months of 2020, $47 million (8%) was invested in Western Canada Production compared to $96 million (12%) in the same period in 2019. Capital expenditures in 2020 related primarily to resource play development targeting the Spirit River Formation at Ansell and the Montney Formation at Wembley.

U.S. Refining

During the first three months of 2020, $163 million (27%) was invested in U.S. Refining compared to $129 million (16%) in the same period in 2019. Capital expenditures in 2020 related primarily to the the crude oil flexibility project at the Lima Refinery.

Canadian Refined Products

During the first three months of 2020, $2 million (1%) was invested in Canadian Refined Products compared to $10 million (2%) in the same period in 2019.

Offshore Operations

Asia Pacific

During the first three months of 2020, $30 million (5%) was invested in Asia Pacific compared to $59 million (7%) in the same period in 2019. Capital expenditures in 2020 related primarily to the continued development of Liuhua 29-1.

Atlantic

During the first three months of 2020, $77 million (13%) was invested in Atlantic compared to $221 million (27%) in the same period in 2019. Capital expenditures in 2020 related primarily to the West White Rose Project.

Corporate

During the first three months of 2020, $22 million (3%) was invested in Corporate compared to $26 million (3%) in the same period in 2019.

Drilling Activity

Integrated Corridor Operations

The following table discloses the number of wells drilled during the three months ended March 31, 2020 and 2019:

	Three months ended March 31,
	2020		2019
Wells Drilled(wells)(1)	Gross	Net	Gross	Net
Thermal developments	41	41	40	40
Non-thermal developments	20	20	17	17
Western Canada	10	6	14	12
Total	71	67	71	69

⁽¹⁾  Excludes service/stratigraphic test wells for evaluation purposes.

Offshore Operations

There was no Offshore drilling activity during the three months ended March 31, 2020.

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2.4        Financial Strategic Plan

During the first quarter of 2020:

• The Company took a series of actions to fortify its business in response to challenging global market conditions, including the reduction of the 2020 capital program by $900 million and initiation of additional cost-saving measures. These initiatives reflect the Company's commitment to capital discipline, which includes maintaining the strength of its balance sheet while protecting value in an extended lower commodity price environment;

• The Company repaid the maturing 5.00% notes; the amount paid to note holders was $400 million;

• The Board of Directors declared a quarterly dividend of $0.125 per common share, or $125 million, for the fourth quarter of 2019; the dividends were paid on April 1, 2020, to shareholders of record at the close of business on March 17, 2020; and

• Dividends of $9 million were declared on preferred shares for the first quarter of 2020, and were paid on March 31, 2020, to shareholders of record at the close of business on March 17, 2020.

On April 7, 2020, the Company entered into a $500 million unsecured non-revolving term credit facility which matures on April 7, 2022. Interest payable is based on Bankers’ Acceptance or CAD Prime Rates.

On April 20, 2020, the Company announced further reduction to the 2020 capital program by $700 million.

3.0        Business Environment

Average Benchmarks

		Three months ended
		Mar. 31		Dec. 31		Sept. 30	Jun. 30	Mar. 31
Average Benchmarks Summary		2020		2019		2019	2019	2019
West Texas Intermediate (“WTI”) crude oil(1)	(US$/bbl)	46.17		56.96		56.45	59.82	54.90
Brent crude oil(2)	(US$/bbl)	50.26		63.25		61.94	68.82	63.20
Western Canadian Select (“WCS”) at Hardisty(3)	(US$/bbl)	25.64		41.13		44.21	49.14	42.61
WCS at Cushing(4)	(US$/bbl)	39.55		50.41		51.15	55.07	51.75
Light/heavy crude oil differential for WTI less WCS at Hardisty	(US$/bbl)	20.53		15.83		12.24	10.68	12.29
Light/heavy crude oil differential for WTI less WCS at Cushing	(US$/bbl)	6.62		6.55		5.30	4.75	3.15
Condensate at Edmonton	($/bbl)	61.74		69.98		68.70	74.73	67.22
Synthetic at Edmonton	($/bbl)	57.99		74.29		75.12	80.23	70.02
NYMEX natural gas(4)	(US$/mmbtu)	1.95		2.50		2.39	2.64	3.15
NOVA Inventory Transfer (“NIT”) natural gas	($/GJ)	2.03		2.21		0.99	1.11	1.84
Chicago Regular Unleaded Gasoline	(US$/bbl)	50.88		64.39		71.71	81.40	63.41
Chicago Ultra-low Sulphur Diesel	(US$/bbl)	60.45		78.09		75.26	81.50	77.10
Chicago 3:2:1 crack spread	(US$/bbl)	8.32		12.06		16.44	21.61	13.08
U.S./Canadian dollar exchange rate	(US$)	0.745		0.758		0.757	0.748	0.752
Chinese Yuan ("RMB")/Canadian dollar exchange rate	(RMB)	5.198		5.337		5.315	5.102	5.076
Canadian $ Equivalents(5)
WTI crude oil	($/bbl)	61.97		75.15		74.57	79.97	73.01
Brent crude oil	($/bbl)	67.46		83.44		81.82	92.00	84.04
WCS at Hardisty	($/bbl)	34.42		54.26		58.40	65.70	56.66
WCS at Cushing	($/bbl)	53.09		66.50		67.57	73.62	68.82
NYMEX natural gas	($/mmbtu)	2.62		3.30		3.16	3.53	4.19
Synthetic/WTI differential	($/bbl)	(3.98	)	(0.86	)	0.55	0.26	(2.99	)

⁽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. Quoted prices are indicative of the Index for WCS at Hardisty, Alberta, set in the month prior to delivery.

⁽⁴⁾  Quoted prices are indicative of the Index for WCS at Cushing, Oklahoma, set in the month prior to delivery.

⁽⁵⁾  Prices quoted are average settlement prices during the period.

⁽⁶⁾  Prices quoted are calculated using U.S. dollar benchmark commodity prices and monthly average U.S./Canadian dollar exchange rates.

HUSKY ENERGY INC.| Q1 | Management's Discussion and Analysis |9

Crude Oil Benchmarks

Global crude oil benchmarks in the first quarter of 2020 decreased relative to the first quarter of 2019. WTI averaged US$46.17/bbl during the first quarter of 2020, compared to US$54.90/bbl during the first quarter of 2019. Brent averaged US$50.26/bbl during the first quarter of 2020, compared to US$63.20/bbl during the first quarter of 2019. WCS at Hardisty averaged US$25.64/bbl during the first quarter of 2020, compared to US$42.61/bbl during the first quarter of 2019.

The price received by the Company for crude oil production in the Integrated Corridor 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 in the Integrated Corridor is classified as either heavy crude oil or bitumen, which trades at a discount to light crude oil and can be impacted by the geographical market that it is exported to. The Company’s crude oil and NGL production was 77% heavy crude oil and bitumen in the first quarter of 2020 compared to 79% in the first quarter of 2019.

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 first quarter of 2020 compared to the first quarter of 2019, primarily due to the decrease in crude oil benchmark pricing.

Natural Gas Benchmarks

The price received by the Company for natural gas from Western Canada Production 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 Integrated Corridor operations, helping to mitigate the impact of weak natural gas benchmark prices on results.

Refining Benchmarks

Lloydminster Heavy Oil Value Chain

The Company produces a sweet synthetic crude oil, the Husky Synthetic Blend ("HSB"), at the Lloydminster Upgrader. The price realized by HSB is primarily driven by the price of WTI and by the supply and demand of sweet synthetic crude oil from Western Canada, which influences the synthetic to WTI differential.

U.S. Refining

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 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 16% 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”).

HUSKY ENERGY INC.| Q1 | Management's Discussion and Analysis |10

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. and Asia Pacific operations and U.S. dollar denominated debt. The Canadian dollar averaged US$0.745 in the first quarter of 2020 compared to US$0.752 in the first quarter of 2019.

A portion of the Company’s long-term sales contracts in Asia Pacific are priced in 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 5.198 in the first quarter of 2020 compared to RMB 5.076 in the first quarter of 2019.

Sensitivity Analysis

The following table is indicative of the impact of changes in certain key variables in the first quarter of 2020 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 first quarter of 2020. 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.

	2020
	First 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)	46.17	US $1.00/bbl	102		0.10		76		0.08
NYMEX benchmark natural gas price(5)	1.95	US $0.20/mmbtu	—		—		—		—
WTI/WCS at Cushing differential(6)	6.62	US $1.00/bbl	(2	)	—		(1	)	—
Canadian asphalt margins	26.14	Cdn $1.00/bbl	9		0.01		7		0.01
Chicago 3:2:1 crack spread	8.32	US $1.00/bbl	103		0.10		80		0.08
Exchange rate (US $ per Cdn $)(3)(7)	0.745	US $0.01	(6	)	(0.01	)	(3	)	—

⁽¹⁾  Excludes mark to market accounting impacts.

⁽²⁾  Based on 1,005.1 million common shares outstanding as at March 31, 2020.

⁽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.| Q1 | Management's Discussion and Analysis |11

4.0        Results of Operations

4.1        Integrated Corridor

Lloydminster Heavy Oil Value Chain

Lloydminster Heavy Oil Value Chain Earnings Summary	Three months ended March 31,
($ millions)	2020		2019
Gross Revenues(9)
Synthetic crude oil and refined product revenues	505		448
Blended crude oil(8)	480		460
Other revenues(1)	185		274
	1,170		1,182
Royalties	(17	)	(34	)
Marketing and other(9)	(29	)	46
Revenue, net of royalties	1,124		1,194
Expenses
Purchases of crude oil and products(9)	526		494
Production, operating and transportation expenses(9)	291		297
Selling, general and administrative expenses	51		39
Operating margin(7)	256		364
Depletion, depreciation, amortization and impairment (“DD&A”)	232		236
Net earnings (loss)	(13	)	74
Select operating data:
Total sales volumes (mboe/day)	194.4		156.0
Synthetic crude oil and refined product	86.5		67.4
Blended crude oil	107.9		88.6
Total realized price per unit sold ($/boe)	55.67		64.66
Synthetic crude oil and refined product	64.13		73.83
Blended crude oil	48.87		57.70
Total daily gross production (mboe/day)	145.4		140.0
Medium crude oil (mbbls/day)	1.7		1.6
Heavy crude oil (mbbls/day)	30.4		27.6
Bitumen (mbbls/day)	111.0		108.0
Conventional natural gas (mmcf/day)	13.4		16.7
Total throughput (mbbls/day)	106.1		94.0
Upgrading throughput(mbbls/day)(2)	77.5		71.2
Lloydminster Refinery throughput (mbbls/day)(3)	28.6		22.8
	��
Unit operating cost($/boe)(4)(5)(6)	11.74		15.06
Unit operating margin($/boe)(5)(6)	17.93		29.26

⁽¹⁾  Includes revenues from pipeline construction activities, the Lloydminster and Minnedosa Ethanol plants and processing income.

⁽²⁾  Throughput includes diluent returned to the field.

⁽³⁾  Includes all crude oil, feedstock, intermediate feedstock and blend-stocks used in producing sales volumes from the refinery.

⁽⁴⁾  Excludes operating costs not directly attributable to the sale of synthetic crude and refined product, and blended crude oil.

⁽⁵⁾  Excludes revenue and expenses not directly attributable to sale of synthetic crude and refined product, and blended crude oil.

⁽⁶⁾  Per unit cost calculated based on sales volumes.

⁽⁷⁾  Operating margin is a non-GAAP measure. Refer to Section 10.3.

⁽⁸⁾  Blended heavy crude oil and bitumen.

⁽⁹⁾  Results reported for 2019 have been recast to reflect a change in reclassification of intersegment sales eliminations and a change in presentation of the Integrated Corridor and Offshore business units.

HUSKY ENERGY INC.| Q1 | Management's Discussion and Analysis |12

Lloydminster Heavy Oil Value Chain Financial Highlights

Change in results for the three months ended March 31
($ millions)
Synthetic crude oil and refined product revenues	Increased	Increased primarily due to higher revenue from HSB and asphalt sales in the first quarter of 2020.
Blended crude oil	Increased	Increased primarily due to higher sales volumes resulting from higher bitumen and heavy crude oil production from the Company's thermal projects in the first quarter of 2020, partially offset by lower commodity pricing.
Other revenues	Decreased	Decreased primarily due to lower pipeline construction revenue in the first quarter of 2020.
Marketing and other	Decreased	Decreased primarily due to the significant decline in global commodity prices, which resulted in inventory impairment on the Keystone held for trading inventory, combined with fewer arbitrage opportunities in the first quarter of 2020.
Purchases of crude oil and products	Increased	Increased primarily due to inventory impairments resulting from lower average WCS prices in the first quarter of 2020, partially offset by lower crude oil feedstock prices.
Net earnings (loss)	Decreased	Decreased primarily due to the same factors which impacted operating margins as discussed above.

Lloydminster Heavy Oil Value Chain Operational Highlights

Change in operational performance for the three months ended March 31
Total sales volumes (mboe/day)
Synthetic crude oil and refined product	Increased	Increased primarily due to higher volumes of HSB and asphalt sales in the first quarter of 2020.
Blended crude oil	Increased	Increased primarily due to a higher volume of heavy crude oil sales in the first quarter of 2020.
Total realized price per unit sold ($/boe)
Synthetic crude oil and refined product	Decreased	Decreased primarily due to lower refined product pricing from the significant decline in the global commodity prices and the wider synthetic differential in the first quarter of 2020.
Blended crude oil	Decreased	Decreased primarily due to lower commodity pricing from the significant decline in global commodity prices and the wider light/heavy crude oil differential in the first quarter of 2020.
Unit operating cost($/bbl)	Decreased	Decreased primarily due to the higher sales volumes, combined with cost saving initiatives in the first quarter of 2020.
Unit operating margin ($/bbl)	Decreased	Decreased primarily due to the decline in refined product and crude oil prices, partially offset by the increase in sales volumes in the first quarter of 2020.

HUSKY ENERGY INC.| Q1 | Management's Discussion and Analysis |13

Oil Sands

Oil Sands Earnings Summary	Three months ended March 31,
($ millions)	2020		2019
Gross revenues(2)	103		120
Royalties	(1	)	(2	)
Marketing and other	(50	)	19
Revenues, net of royalties	52		137
Expenses
Purchases of crude oil and products(2)	100		12
Production, operating and transportation expenses	35		40
Selling, general and administrative expenses	9		7
Operating margin	(92	)	78
Depletion, depreciation, amortization and impairment	361		23
Net earnings (loss)	(343	)	35
Select operating data:
Total sales volumes (mbbls/day)
Diluted bitumen (mbbls/day)	35.2		22.9
Total realized price per unit sold ($/bbl)
Diluted bitumen ($/bbl)	31.88		57.82
Total daily gross production (mbbls/day)
Bitumen (mbbls/day)	27.0		22.3
Unit operating cost ($/bbl)(1)	11.05		19.34
Unit operating margin ($/bbl)(1)	(24.92	)	38.91

⁽¹⁾  Per unit cost calculated based on sales volumes.

⁽²⁾  Results reported for 2019 have been recast to reflect a change in reclassification of intersegment sales eliminations and a change in presentation of the Integrated Corridor and Offshore business units.

Oil Sands Financial Highlights

Change in results for the three months ended March 31
($ millions)
Gross revenues	Decreased	Decreased primarily due to the lower average WCS benchmark prices, partially offset by a higher volume of diluted bitumen sales in the first quarter of 2020.
Marketing and other	Decreased	Decreased primarily due to the significant decline in global commodity prices that resulted in an inventory impairment on the held for trading inventory on the Cochin and Flanagan pipelines.
Purchases of crude oil and products	Increased	Increased primarily due to the change in inventory quarter over quarter, combined with the higher volume of diluent purchases in the first quarter of 2020.
DD&A	Increased	Increased primarily due the recognition of a pre-tax impairment of $337 million due to declines in current and forecasted crude oil prices.
Net earnings (loss)	Decreased	Decreased primarily due the same factors which impacted operating margin and DD&A as discussed above, partially offset by a tax recovery due to the lower earnings in the first quarter of 2020.

Oil Sands Operational Highlights

Change in operational performance for the three months ended March 31
Total sales volumes (mbbls/day)	Increased	Increased primarily due to the higher production of bitumen from the Sunrise Energy Project.
Total realized price per unit sold ($/bbl)	Decreased	Decreased primarily due to lower commodity pricing due to the significant decline in global commodity prices.
Unit operating cost($/bbl)	Decreased	Decreased primarily due to the higher sales volumes in the first quarter of 2020.
Unit operating margin ($/bbl)	Decreased	Decreased primarily due to the change in inventory quarter over quarter, combined with the lower average WCS prices in the first quarter of 2020, partially offset by the higher sales volumes in the first quarter of 2020.

HUSKY ENERGY INC.| Q1 | Management's Discussion and Analysis |14

Western Canada Production

Western Canada Production Earnings Summary	Three months ended March 31,
($ millions)	2020		2019
Gross revenues(1)	119		150
Royalties	(9	)	(13	)
Marketing and other(1)	6		50
Revenues, net of royalties	116		187
Expenses
Purchases of crude oil and products(1)	13		2
Production, operating and transportation expenses(1)	74		83
Selling, general and administrative expenses	26		27
Operating margin	3		75
Depletion, depreciation, amortization and impairment	301		77
Net loss	(221	)	(6	)
Select operating data:
Total sales volumes (mboe/day)(2)	62.6		69.2
Light crude oil (mbbls/day)	7.5		7.3
NGL (mbbls/day)	10.9		14.4
Conventional natural gas (mmcf/day)	265.5		285.1
Total realized price per unit sold ($/boe)	18.92		23.11
Light crude oil ($/bbl)	48.66		60.25
Conventional natural gas & NGL ($/mcf)	2.47		3.12
Unit operating cost ($/boe)	13.00		13.17

⁽¹⁾  Results reported for 2019 have been recast to reflect a change in reclassification of intersegment sales eliminations and a change in presentation of the Integrated Corridor and Offshore business units.

⁽²⁾  Sales volumes approximate total daily gross production.

Western Canada Production Financial Highlights

Change in results for the three months ended March 31
($ millions)
Gross revenues	Decreased	Decreased primarily due to lower sales volumes combined with lower realized commodity prices in the first quarter of 2020.
Marketing and other	Decreased	Decreased primarily due to reduced margin in natural gas exports as the Canada to U.S gas price spread weakened in the first quarter of 2020.
DD&A	Increased	Increased primarily due to the recognition of a pre-tax impairment of $249 million due to declines in current and forecasted crude oil prices.
Net loss	Increased	Increased primarily due the same factors which impacted operating margin and DD&A as discussed above, partially offset by a tax recovery due to the lower earnings in the first quarter of 2020.

Western Canada Production Operational Highlights

Change in operational performance for the three months ended March 31
($ millions)
Total sales volumes (mboe/day)	Decreased	Decreased primarily due to lower production of NGL and conventional natural gas in the first quarter of 2020.
Total realized price per unit sold ($/boe)	Decreased	Decreased primarily due to lower commodity pricing from the significant decline in global commodity prices.

HUSKY ENERGY INC.| Q1 | Management's Discussion and Analysis |15

U.S. Refining

U.S. Refining Earnings Summary	Three months ended March 31,
($ millions)	2020		2019
Gross revenues(4)	2,064		2,337
Marketing and other(4)	58		38
Revenues	2,122		2,375
Expenses
Purchases of crude oil and products	2,430		1,879
Production, operating and transportation expenses(4)	220		215
Selling, general and administrative expenses	22		12
Operating margin	(550	)	269
Depletion, depreciation, amortization and impairment	132		116
Net earnings (loss)	(534	)	199
Select operating data:
Total throughput(mbbls/day)(1)	201.7		229.4
Lima Refinery (mbbls/day)(1)	131.4		171.4
BP-Husky Toledo Refinery (mbbls/day)(1)(2)	70.3		58.0
Unit refining and marketing margin (US$/bbl crude throughput)(5)	(12.68	)	18.65
Refinery inventory (mmbbls)(3)	8.9		8.6

⁽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%).

⁽³⁾  Feedstock and refined products are included in refinery inventory.

⁽⁴⁾  Results reported for 2019 have been recast to reflect a change in reclassification of intersegment sales eliminations and a change in presentation of the Integrated Corridor and Offshore business units.

⁽⁵⁾  Refining and marketing margin is a non-GAAP measure. Refer to Section 10.3.

U.S. Refining Financial Highlights

Change in results for the three months ended March 31
($ millions)
Gross revenues	Decreased	Decreased primarily due to the lower average realized refined product prices combined with lower sales volumes at the Lima Refinery, partially offset by higher sales volumes at the BP-Husky Toledo Refinery.
Purchases of crude oil and products	Increased	Increased primarily due to the recognition of a pre-tax inventory impairment of $284 million on refined and feedstock inventory due to the falling commodity price environment at the end of the first quarter of 2020, combined with the realization of the 2018 year-end lower cost crude oil feed stock at the Lima Refinery, in the first quarter of 2019.
Net earnings (loss)	Decreased	Decreased primarily due to the same factors that impacted operating margin as discussed above.

U.S. Refining Operational Highlights

Change in operational performance for the three months ended March 31
Total throughput(mbbls/day)
Lima Refinery	Decreased	Decreased primarily due to the extended ramp-up of the Lima Refinery and management's decision to reduce refinery operating rates to match reduced product demand.
BP-Husky Toledo Refinery	Increased	Increased primarily due to higher refinery mechanical availability, as the refinery availability was restricted due to unplanned maintenance in the first quarter of 2019. The increase was partially offset by the decision to reduce refinery operating rates due to reduced product demand in the first quarter of 2020.
Unit refining and marketing margin (US$/bbl crude throughput)	Decreased	Decreased primarily due to the tightening of the refining margins and inventory impairments from the significant decline in global commodity prices.

HUSKY ENERGY INC.| Q1 | Management's Discussion and Analysis |16

Canadian Refined Products

Canadian Refined Products Earnings Summary	Three months ended March 31,
($ millions)	2020		2019
Gross revenues	456		574
Expenses
Purchases of crude oil and products	422		495
Production, operating and transportation expenses	16		38
Selling, general and administrative expenses	13		3
Operating margin	5		38
Depletion, depreciation, amortization and impairment	15		22
Net earnings (loss)	(9	)	9
Select operating data:
Fuel sales volume, including wholesale
Fuel sales (millions of litres/day)	6.9		7.5
Fuel sales per retail outlet (thousands of litres/day)	12.6		12.0

Canadian Refined Products Financial Highlights

Change in results for the three months ended March 31
($ millions)
Gross revenues	Decreased	Decreased primarily due to the decline in gasoline and diesel prices in the first quarter of 2020.
Purchases of crude oil and products	Decreased	Decreased primarily due to the decline in gasoline and diesel prices in the first quarter of 2020.
Net earnings (loss)	Decreased	Decreased primarily due to the narrowing of the marketing margins.

HUSKY ENERGY INC.| Q1 | Management's Discussion and Analysis |17

4.2        Offshore

Asia Pacific

Asia Pacific Earnings Summary	Three months ended March 31,
($ millions, except where indicated)	2020		2019
Gross revenues	274		281
Royalties	(14	)	(15	)
Revenues, net of royalties	260		266
Expenses
Production, operating and transportation expenses	19		18
Selling, general and administrative expenses	11		14
Operating margin	230		234
Depletion, depreciation, amortization and impairment	72		87
Net earnings	128		116
Select operating data:
Total sales volume (mboe/day)(1)(2)(3)	44.3		46.1
NGL(mbbls/day)(2)(3)	9.4		10.3
Conventional natural gas (mmcf/day)(2)(3)	209.7		215.0
Total realized price per unit sold ($/boe)	80.84		79.73
NGL($/bbl)	66.91		72.33
Conventional natural gas($/mcf)	14.10		13.64
Unit operating cost ($/boe)(4)	6.14		6.11

⁽¹⁾  Sales volumes approximates total daily gross production.

⁽²⁾  Reported sales volumes include Husky’s working interest production from the Liwan Gas Project (49%).

⁽³⁾  Reported sales volumes include Husky’s working interest production from the BD Project (40%). Revenues and expenses related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under the equity method for consolidated financial statement purposes.

⁽⁴⁾  Reported operating costs include Husky’s working interest production from the BD Project (40%). Revenues and expenses related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under the equity method for consolidated financial statement purposes.

Asia Pacific Financial Highlights

Change in results for the three months ended March 31
($ millions)
Net Earnings	Increased	Net earnings were comparable to the first quarter of 2019.

Asia Pacific Operational Highlights

Change in operational performance for the three months ended March 31
($ millions)
Total sales volume (mboe/day)	Decreased	Decreased primarily due to lower gas production at the Liwan Gas Project, partially offset by higher production at the BD Project.

HUSKY ENERGY INC.| Q1 | Management's Discussion and Analysis |18

Atlantic

Atlantic Earnings Summary	Three months ended March 31,
($ millions, except where indicated)	2020		2019
Gross revenues	95		28
Royalties	(4	)	(7	)
Revenues, net of royalties	91		21
Expenses
Purchases of crude oil and products(2)	10		(21	)
Production, operating and transportation expenses	51		68
Selling, general and administrative expenses	7		1
Operating margin	23		(27	)
Depletion, depreciation, amortization and impairment	939		42
Net loss	(691	)	(61	)
Select operating data:
Total sales volumes (mbbls/day)
Light crude oil (mbbls/day)	15.4		4.4
Total realized price per unit sold ($/bbl)
Light crude oil ($/bbl)	67.11		69.18
Total daily gross production (mbbls/day)
Light crude oil (mbbls/day)	19.6		7.6
Unit operating cost($/bbl)(1)	33.49		159.26

⁽¹⁾  Per unit cost calculated based on sales volumes.

⁽²⁾  Results reported for 2019 have been recast to reflect a change in reclassification of intersegment sales eliminations and a change in presentation of the Integrated Corridor and Offshore business units.

Atlantic Financial Highlights

Change in results for the three months ended March 31
($ millions)
Gross revenues	Increased	Increased primarily due to higher sales volumes in the first quarter of 2020, partially offset by lower realized sales pricing.
Purchases of crude oil and products	Increased	Increased primarily due to inventory impairments as a result of the lower commodity price environment at the end of the first quarter of 2020, combined with the timing difference of production sales between the first quarter of 2020 and the first quarter of 2019.
DD&A	Increased	Increased primarily due to the recognition of a pre-tax impairment of $830 million due to declines in current and forecasted crude oil prices and management’s decision to delay capital investment in the West White Rose Project.
Net loss	Increased	Increased primarily due to the same factors which impacted operating margin and DD&A as discussed above, partially offset by a tax recovery due to the lower earnings in the first quarter of 2020.

Atlantic Operational Highlights

Change in operational performance for the three months ended March 31
Total sales volumes (mbbl/day)	Increased	Increased primarily due to the timing of the production sales, combined with the higher production in the first quarter of 2020.
Daily gross production (mbbl/day)	Increased	Increased primarily due to higher production from the White Rose field, which resumed production in mid-August 2019. The increase was partially offset by lower production from the Terra Nova field, which suspended production in December 2019.
Unit operating cost ($/bbl)	Decreased	Decreased primarily due to the higher sales volumes in the first quarter of 2020, combined with the incremental costs incurred in the first quarter of 2019 related to the incident at the White Rose field in late 2018.

HUSKY ENERGY INC.| Q1 | Management's Discussion and Analysis |19

4.3Corporate

Corporate Summary	Three months ended March 31,
($ millions) income (expense)	2020		2019
Production, operating and transportation expenses	—		—
Selling, general and administrative expenses	(44	)	(43	)
Depletion, depreciation and amortization	(22	)	(27	)
Other – net	116		(2	)
Net foreign exchange gain (loss)	(50	)	30
Finance income	13		19
Finance expense	(20	)	(41	)
Recovery of (provisions for) income taxes	(15	)	26
Net loss	(22	)	(38	)

The Corporate segment reported a net loss of $22 million in the first quarter of 2020 compared to a net loss of $38 million in the first quarter of 2019. Other – net income increased by $118 million, primarily due to a net realized and unrealized gain of $109 million on the Company's commodity short-term hedging program. Recovery of income taxes decreased by $41 million, primarily due to the factors discussed in the Consolidated Income Taxes section below.

The net foreign exchange loss increased by $80 million due to items noted below.

Foreign Exchange Summary	Three months ended March 31,
($ millions, except where indicated)	2020		2019
Non-cash working capital gain	14		8
Other foreign exchange gain (loss)	(64	)	22
Net foreign exchange gain (loss)	(50	)	30
U.S./Canadian dollar exchange rates:
At beginning of period	US$0.771		US$0.733
At end of period	US$0.708		US$0.749

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.

Consolidated Income Taxes

Consolidated Income Taxes	Three months ended March 31,
($ millions)	2020		2019
Provisions for (recovery of) income taxes	(541	)	89
Cash income taxes paid	50		84

Consolidated income taxes were a recovery of $541 million in the first quarter of 2020 compared to a provision of $89 million in the first quarter of 2019. The decrease in consolidated income taxes was primarily due to a $363 million deferred income tax recovery associated with the recognition of a pre-tax impairment charge of $1,416 million on crude oil and natural gas assets located in Canada, and lower earnings before income taxes in the first quarter of 2020.

HUSKY ENERGY INC.| Q1 | Management's Discussion and Analysis |20

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 27, 2020. 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, 2019, have not materially changed since December 31, 2019, except as noted below.

The recent COVID-19 pandemic, and actions taken, and that may be taken, by governmental authorities in response thereto, have resulted and may continue to result in, among other things: increased volatility in financial markets and foreign currency exchange rates; disruptions to global supply chains; adverse effects on the health and safety of the Company’s workforce, or guidelines or restrictions to protect health and safety of such workforces, rendering employees unable to work or travel; temporary operational restrictions; and an overall slowdown in the global economy. In particular, the COVID-19 pandemic has resulted in, and may continue to result in, a reduction in the demand for, and prices of, commodities that are closely linked to the Company’s financial performance, including crude oil, refined petroleum products (such as jet fuel and gasoline), natural gas and electricity, and also increases the risk that storage for crude oil and refined petroleum products could reach capacity in certain geographic locations in which the Company operates. A prolonged period of decreased demand for, and prices of, these commodities, and any applicable storage constraints, could also result in the Company voluntarily curtailing or shutting in production and a decrease in the Company’s refined product volumes and refinery utilization rates, which could adversely impact the Company’s business, financial condition and results of operations.

The COVID-19 pandemic continues to rapidly evolve and the extent to which it may impact the Company’s business, financial condition and results of operations, as well as the Company’s future capital expenditures and other discretionary items, will depend on future developments, which are highly uncertain and cannot be predicted with any degree of confidence. To the extent that the COVID-19 pandemic adversely affects the Company’s business, financial condition and results of operations, it may also have the effect of heightening many of the other risks described in the Company’s 2019 Annual Information Form, such as risks relating to: the Company’s ability to maintain its credit ratings; financing ongoing project development costs, including costs associated with the Company’s joint venture arrangements; meeting the Company’s financial obligations; and otherwise complying with the covenants contained in the agreements that govern the Company’s indebtedness.

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 March 31, 2020, the Company was party to crude oil purchase and sale derivative contracts to mitigate its exposure to fluctuations in the benchmark price between the time a sales agreement is entered into and the time inventory is delivered. The Company was also party to third party physical natural gas purchase and sale derivative contracts in order to mitigate commodity price fluctuations. Refer to Note 14 of the condensed interim consolidated financial statements.

During the three months ended March 31, 2020, the Company continued a commodity short-term hedging program using put options to manage risks related to volatility of commodity prices.

WTI Crude Oil Put Option Contracts(1)
Type	Transaction	Term	Volume (bbls/day)	Put Price (US$bbl)
Put options	Bought	April - June 2020	32,143	52.19
Put options	Sold	April - June 2020	25,549	46.08

⁽¹⁾  Prices reported are the weighted average prices for the period.

HUSKY ENERGY INC.| Q1 | Management's Discussion and Analysis |21

Foreign Exchange Risk Management

At March 31, 2020, Cdn $3.4 billion or 62% 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 March 31, 2020, Cdn $3.4 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 months ended March 31, 2020, the Company incurred an unrealized loss of $242 million arising from the translation of the debt, net of tax recovery of $33 million 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 the Company 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.

Credit and Contract Risk Management

Credit and contract risk represent the financial loss that the Company would suffer if a counterparty in a transaction fails to meet its obligations in accordance with the agreed terms. The Company actively manages its exposure to credit and contract execution risk from both a customer and a supplier perspective. The Company’s accounts receivables are broad based with customers in the energy industry and midstream and end user segments and are subject to normal industry risks. The Company’s policy to mitigate credit risk includes granting credit limits consistent with the financial strength of the counterparties and customers, requiring financial assurances as deemed necessary, reducing the amount and duration of credit exposures and close monitoring of all accounts. The Company is closely monitoring counterparty and customer risk in the current economic climate. At March 31, 2020 the Company’s accounts receivable balance was 98% current or less than 31 days past due.

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 March 31, 2020, the Company had the following available credit facilities:

Credit Facilities
($ millions)	Available	Unused
Operating facilities(1)	900	454
Syndicated credit facilities(2)	4,000	2,951
Total	4,900	3,405

⁽¹⁾  Consists of demand credit facilities.

⁽²⁾  Commercial paper outstanding is supported by the Company’s syndicated credit facilities.

HUSKY ENERGY INC.| Q1 | Management's Discussion and Analysis |22

At March 31, 2020, the Company had $3,405 million of unused credit facilities of which $2,951 million are long-term committed credit facilities and $454 million are short-term uncommitted credit facilities. A total of $446 million short-term uncommitted borrowing credit facilities was used in support of outstanding letters of credit and $450 million of long-term committed borrowing credit facilities was used in support of commercial paper. At March 31, 2020, the Company had $599 million outstanding under its $2.0 billion facility expiring June 19, 2022, and no direct borrowings under its $2.0 billion facility expiring 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.

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 a debt to capital ratio 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 credit agreement divided by total debt, shareholders’ equity and certain adjusting items specified in the credit agreement. This covenant is used to assess the Company's financial strength. If the Company does not comply with this financial covenant under the syndicated credit facilities, there is the risk that repayment could be accelerated. The Company was in compliance with the syndicated credit facility financial covenant at March 31, 2020, and assessed the risk of non-compliance to be low.

Working capital is the amount by which current assets exceed current liabilities. At March 31, 2020, working capital was $24 million compared to $302 million at December 31, 2019.

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 March 31, 2020.

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 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.

On March 3, 2020, the Company filed a universal short form base shelf prospectus (“the 2020 U.S. Shelf Prospectus”) with the Alberta Securities Commission. On March 4, 2020, the Company’s related U.S. registration statement filed with the SEC containing the 2020 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 April 4, 2022. During the 25-month period that the 2020 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 12, 2020, the Company repaid the maturing 5.00% notes. The principal paid to noteholders was $400 million.

As at March 31, 2020, the Company had $3.0 billion in unused capacity under the 2019 Canadian Shelf Prospectus and US$3.0 billion in unused capacity under the 2020 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 2020 U.S. Shelf Prospectus and related U.S. registration statement is subject to market conditions at the time of sale.

On April 7, 2020, the Company entered into a $500 million unsecured non-revolving term credit facility that matures on April 7, 2022. Interest payable is based on Bankers’ Acceptance or CAD Prime Rates.

HUSKY ENERGY INC.| Q1 | Management's Discussion and Analysis |23

6.2        Capital Structure

Capital Structure	March 31, 2020
($ millions)	Outstanding
Total debt(1)	5,895
Shareholders' equity	16,121

⁽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 $22.0 billion as at March 31, 2020 (December 31, 2019 – $22.8 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 a debt to capital ratio and a debt to trailing funds from operations ratio (refer to Section 10.3). The debt to capital ratio is reviewed to ensure compliance with a leverage covenant in the Company’s credit facilities that limits debt to capital (subject to specific definitions in the credit agreements) to 65% or less. The Company was in compliance with this covenant at March 31, 2020 and considers the risk of non-compliance to be low. At March 31, 2020, the debt to trailing funds from operations ratio was 2.5 times (December 31, 2019 – 1.7 times). The increase in the Company’s debt to trailing funds from operations ratio reflects the impact of the sharp decline in the global economic environment from COVID-19 and falling commodity prices which resulted in significantly lower funds from operations. The Company has taken measures to strengthen its financial position and navigate through this commodity down cycle including but not limited to a reduction of 2020 budgeted capital and operating spending. The Company targets a debt to funds from operations ratio of less than 2.0 times over the longer-term.

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, 2019 under the caption “Liquidity and Capital Resources” which summarizes contractual obligations and other commercial commitments as at December 31, 2019. During the three months ended March 31, 2020, there were no material changes to the Company's contractual obligations or non-cancellable commitments, except as noted below.

During the three months ended March 31, 2020, the Company’s unconditional purchase obligations related to the purchase of refined products for Canadian truck transportation and retail networks decreased by $5.6 billion due to declining gasoline and diesel prices.

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% 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 months ended March 31, 2020, the Company charged HMLP $55 million, related to construction and management services. For the three months ended March 31, 2020, the Company had purchases from HMLP of $66 million, related to the use of the pipeline for the Company’s blending, transportation and storage activities. As at March 31, 2020, the Company had $87 million due from HMLP and $16 million due to HMLP.

HUSKY ENERGY INC.| Q1 | Management's Discussion and Analysis |24

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, 2019, 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.

In early March 2020, the World Health Organization declared the COVID-19 coronavirus outbreak to be a pandemic. Responses to the spread of COVID-19 have resulted in significant disruption to business operations and a significant increase in economic uncertainty, with more volatile commodity prices and currency exchange rates, and a marked decline in long-term interest rates. These events are resulting in a challenging economic climate in which it is difficult to reliably estimate the length or severity of these developments and their financial impact. The results of the potential economic downturn and any potential resulting direct and indirect impact to the Company has been considered in management’s estimates described above at the period end; however there could be a further prospective material impact in future periods.

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

The condensed interim consolidated financial statements have been prepared, for all periods presented, following the same accounting policies and methods of computation as described in Note 3 to the consolidated financial statements for the fiscal year ended December 31, 2019.

9.0        Outstanding Share Data

Authorized:

• unlimited number of common shares

• unlimited number of preferred shares

Issued and outstanding: April 23, 2020:

• 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                        19,792,866

• stock options exercisable                     9,915,533

HUSKY ENERGY INC.| Q1 | Management's Discussion and Analysis |25

10.0        Reader Advisories

10.1        Forward-Looking Statements

Certain statements in this document are forward-looking statements and information (collectively, “forward-looking statements”), within the meaning of the applicable Canadian securities legislation, Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended. The forward-looking statements contained in this document are forward-looking and not historical facts.

Some of the forward-looking statements may be identified by statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as “will likely result”, “are expected to”, “will continue”, “is anticipated”, “is targeting”, “is estimated”, “intend”, “plan”, “projection”, “could”, “aim”, “vision”, “goals”, “objective”, “target”, “schedules” and “outlook”). In particular, forward-looking statements in this document include, but are not limited to, references to:

• with respect to the business, operations and results of the Company generally: the Company’s general strategic plans and growth strategies; the Company’s 2020 production and throughput guidance; the Company’s 2020 capital guidance, broken down into Integrated Corridor, Offshore and Corporate; and the Company’s target debt to funds from operations ratio;

• with respect to the Lloydminster Heavy Oil Value Chain: the expected timing of the routine maintenance turnaround at the Lloydminster Upgrader; and the expected timing of completion of construction of storage tanks at the Hardisty Terminal;

• with respect to Oil Sands, the expected timing of a planned turnaround at Plant 1B at the Sunrise Energy Project;

• with respect to U.S. Refining, the estimated investment in the rebuild of the Superior Refinery and anticipated insurance recoveries for property damage and lost income associated therewith;

• with respect to the Company's Offshore business in Asia Pacific: the expected timing of installation of the control system and connecting flow lines at, and first gas sales from, Liuhua 29‑1; drilling plans at Block 15/33; the expected timing of drilling seven production wells at MDA and MBH; the expected timing of completion of construction of the FPU at MDA and MBH; plans to develop the additional MDK shallow water field; the expected timing that tendering will be conducted for a leased FPU at the MAC field; and the anticipated timing of a final investment decision and of the first production of natural gas at the MAC field.

There are numerous uncertainties inherent in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary from production estimates.

Although the Company believes that the expectations reflected by the forward-looking statements presented in this document are reasonable, the Company’s forward-looking statements have been based on assumptions and factors concerning future events that may prove to be inaccurate. 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, 2019, this Management's Discussion and Analysis, 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.

HUSKY ENERGY INC.| Q1 | Management's Discussion and Analysis |26

New factors emerge from time to time and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company's course of action would depend upon management’s assessment of the future considering all information available to it at the relevant time. Any forward-looking statement speaks only as of the date on which such statement is made and, except as required by applicable securities laws, the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.

10.2        Cautionary Note Required by National Instrument 51-101

Unless otherwise noted: (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, operating margin, free cash flow, total debt, debt to capital, debt to trailing funds from operations, refining and marketing margin 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 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

Debt to capital is a non-GAAP measure and is equal to total debt and certain adjusting items specified in the Company's credit agreement divided by total debt, shareholder's equity and certain adjusting items specified in such credit agreement. 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 March 31, 2020. 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 March 31, 2020, and December 31, 2019:

Debt to Trailing Funds from Operations
($ millions)	March 31, 2020	December 31, 2019
Total debt	5,895	5,520
Trailing funds from operations	2,317	3,251
Debt to trailing funds from operations	2.5	1.7

HUSKY ENERGY INC.| Q1 | 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
	Mar. 31		Dec. 31		Sept. 30		Jun. 30		Mar. 31		Dec. 31		Sept. 30		Jun. 30
($ millions)	2020		2019		2019		2019		2019		2018		2018		2018
Net earnings (loss)	(1,705	)	(2,341	)	273		370		328		216		545		448
Items not affecting cash:
Accretion	26		27		26		26		27		25		23		25
Depletion, depreciation, amortization and impairment	2,074		3,520		703		643		630		662		672		639
Inventory write-down to net realizable value	362		15		—		—		—		60		—		—
Exploration and evaluation expenses	—		332		—		23		—		22		—		7
Deferred income taxes	(584	)	(789	)	22		(250	)	43		25		156		138
Foreign exchange loss (gain)	3		(11	)	(1	)	(2	)	(12	)	1		(6	)	(2	)
Stock-based compensation	(18	)	(13	)	(9	)	13		7		(50	)	40		33
Gain on sale of assets	(6	)	(3	)	(3	)	—		(2	)	—		—		—
Unrealized mark to market loss (gain)	(91	)	(13	)	4		(4	)	57		(16	)	(22	)	(26	)
Share of equity investment gain	(10	)	5		(19	)	(23	)	(22	)	(16	)	(18	)	(26	)
Gain on insurance recoveries for damage to property	—		(194	)	(13	)	—		—		(253	)	—		—
Other	(1	)	11		5		5		(9	)	2		(2	)	19
Settlement of asset retirement obligations	(24	)	(90	)	(73	)	(41	)	(72	)	(65	)	(45	)	(22	)
Deferred revenue	(17	)	(14	)	(7	)	(5	)	(16	)	(30	)	(25	)	(25	)
Distribution from joint ventures	16		27		113		47		—		—		—		—
Change in non-cash working capital	330		397		(221	)	(42	)	(414	)	730		(35	)	(199	)
Cash flow – operating activities	355		866		800		760		545		1,313		1,283		1,009
Change in non-cash working capital	(330	)	(397	)	221		42		414		(730	)	35		199
Funds from operations	25		469		1,021		802		959		583		1,318		1,208
Funds from operations – basic	0.02		0.47		1.02		0.80		0.95		0.58		1.31		1.20
Funds from operations – diluted	0.02		0.47		1.02		0.80		0.95		0.58		1.31		1.20

Free cash flow

Free cash flow 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. Free cash flow is presented to assist management and investors in analyzing operating performance by the business in the stated period. Free cash flow equals funds from operations less capital expenditures.

Operating margin

Operating margin is a non-GAAP measure which should not be considered an alternative to, or more meaningful than, “revenue, net of royalties” as determined in accordance with IFRS, as an indicator of financial performance. Operating margin is presented to assist management and investors in analyzing operating performance of the Company in the stated period. Operating margin equals revenues net of royalties less purchases of crude oil and products, production, operating and transportation expenses, and selling, general and administrative expenses. Refer to Section 4.0 for the reconciliations to the corresponding GAAP measures.

HUSKY ENERGY INC.| Q1 | Management's Discussion and Analysis |28

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 March 31, 2020 and December 31, 2019:

Total Debt
($ millions)	March 31, 2020	December 31, 2019
Short-term debt	450	550
Long-term debt due within one year	—	400
Long-term debt	5,445	4,570
Total debt	5,895	5,520

Refining and Marketing Margin

Refining and marketing margin is a non-GAAP measure which should not be considered an alternative to, or more meaningful than, “gross revenue” as determined in accordance with IFRS, as an indicator of financial performance. Refining and marketing margin is presented to assist management and investors in analyzing operating performance of the Company in the stated period. Refining and marketing margin equals gross revenue and marketing and other less purchases of crude oil and products.

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.

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, 2019, the 2019 consolidated financial statements, the Annual Information Form dated February 27, 2020 filed with Canadian securities regulatory authorities and the 2019 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 March 31, 2020 are compared to the results for the three months ended March 31, 2019. Discussions with respect to the Company’s financial position as at March 31, 2020 are compared to its financial position as at December 31, 2019. 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 March 31, 2020 that have materially affected, or are reasonably likely to affect, the Company’s ICFR.

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Terms
Asia Pacific	Includes oil and gas exploration and production activities located offshore China and Indonesia
Atlantic	Includes 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 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	Total debt and certain adjusting items specified in the Company's credit agreement divided by total debt, shareholder's equity and certain adjusting items specified in such credit agreement.
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
Synthetic crude 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

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

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