Husky Energy (CVE+A) 40-F 2017 FY Annual report (Canada)

Exhibit 99.1

Disclosure about Oil and Gas Producing Activities - Accounting Standards Codification 932, “Extractive Activities- Oil and Gas” (unaudited)

The following disclosures have been prepared in accordance with FASB Accounting Standards Codification 932, “Extractive Activities - Oil and Gas”.

The unaudited supplemental information on oil and gas exploration and production activities for 2017 and 2016 has been presented in accordance with the revised reserve estimation and disclosure rules, which were not applied retrospectively.

Oil and Gas Reserves

Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations.

Proved developed oil and gas reserves are proved reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Proved undeveloped oil and gas reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Canadian provincial royalties are determined based on a graduated percentage scale, which varies with prices and production volumes. Canadian reserves, as presented on a net basis, assume prices and royalty rates in existence at the time the estimates were made, and Husky’s estimate of future production volumes. Future fluctuations in prices, production rates, or changes in political or regulatory environments could cause Husky’s share of future production from Canadian reserves to be materially different from that presented.

Subsequent to December 31, 2017, no major discovery or other favourable or adverse event is believed to have caused a material change in the estimates of developed or undeveloped reserves as of that date.

Note that the numbers in each column of the tables throughout this exhibit may not add due to rounding.

Results of Operations for Producing Activities⁽¹⁾ (unaudited)

	Year Ended December 31, 2017
($ millions)	Canada			China		Indonesia(2)		Total
Revenues, net of Royalties		3,584			1,013		39		4,636
Production and Operating Expenses		1,547			94		9		1,650
Depreciation, Depletion, Amortization & Impairment		1,863			386		12		2,261
Exploration & Evaluation Expenses		54			4		1		59
Earnings Before Taxes		120			529		17		666
Income Taxes Expense		33			132		7		172
Results of Operations		87			397		10		494
	Year Ended December 31, 2016
($ millions)	Canada			China		Indonesia(2)		Total
Revenues, net of Royalties		2,784			756		—		3,540
Production and Operating Expenses		1,617			92		—		1,709
Depreciation, Depletion, Amortization & Impairment		1,444			363		—		1,807
Exploration & Evaluation Expenses		75			—		—		75
Earnings (Loss) Before Taxes		(352	)		301		—		(51	)
Income Taxes Expense (Recovery)		(96	)		75		—		(21	)
Results of Operations		(256	)		226		—		(30	)

⁽¹⁾ The costs in this schedule exclude corporate overhead, interest expense and other operating costs, which are not directly related to producing activities.

⁽²⁾  Revenue and expenses related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under the equity method for consolidated financial statement purposes.

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (unaudited)

($ millions)	Canada		China		Indonesia(1)		Total
2017
Property Acquisition
Unproved		55		—		—		55
Proved		18		—		—		18
Exploration		157		10		—		167
Development		1,394		10		50		1,454
Total Costs Incurred		1,624		20		50		1,694
2016
Property Acquisition
Unproved		—		—		—		—
Proved		7		—		—		7
Exploration		59		4		—		63
Development		945		106		139		1,190
Total Costs Incurred		1,011		110		139		1,260

⁽¹⁾ Capital expenditures related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under the equity method for consolidated financial statement purposes.

Acquisition costs include costs incurred to purchase, lease or otherwise acquire oil and gas properties.

Exploration costs include the costs of geological and geophysical activity, retaining undeveloped properties and drilling and equipping exploration wells.

Development costs include the costs of (i) drilling and equipping development wells and (ii) facilities to extract, treat, gather and store oil and gas.

Exploration and development costs include administrative costs and depreciation of support equipment directly associated with these activities.

The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2017, by the year in which the costs were incurred:

Withheld Costs (unaudited)

($ millions)	Total		2017		2016		Prior to 2015
Property Acquisitions
Canada		127		65		5		57
China		—		—		—		—
Indonesia(1)		—		—		—		—
Total Property Acquisitions		127		65		5		57
Exploration
Canada		761		151		89		521
China		7		7		—		—
Indonesia(1)		9		2		4		3
Total Exploration		777		160		93		524
Development
Canada		1,429		1,062		367		—
China		307		7		67		233
Indonesia(1)		113		21		92		—
Total Development		1,849		1,090		526		233
Capitalized Interest
Canada		70		28		13		29
China		112		19		20		73
Indonesia(1)		30		2		16		12
Total Capitalized Interest		212		49		49		114
Total Withheld Costs		2,965		1,364		673		928

⁽¹⁾  Capital expenditures related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under the equity method for consolidated financial statement purposes.

Capitalized Costs Relating to Oil and Gas Producing Activities (unaudited)

($ millions)	Canada			China			Indonesia(1)			Total
2017
Proved Properties(2)		36,802			5,003			788			42,593
Unproved Properties		831			7			9			847
		37,633			5,010			797			43,440
Accumulated DD&A, including impairments		(24,017	)		(1,997	)		(11	)		(26,025	)
Net Capitalized Costs		13,616			3,013			786			17,415
2016
Proved Properties(2)		39,916			4,875			362			45,153
Unproved Properties		653			412			43			1,108
		40,569			5,287			405			46,261
Accumulated DD&A, including impairments		(26,250	)		(1,735	)		—			(27,985	)
Net Capitalized Costs		14,319			3,552			405			18,276

⁽¹⁾  Capital expenditures related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under the equity method for consolidated financial statement purposes.

⁽²⁾  Capitalized costs related to proved properties include ARO costs. The gross ARO for the years presented were as follows:

($ millions)	Canada		China		Indonesia(1)		Total
2017		1,907		214		17		2,138
2016		2,245		224		—		2,469

⁽¹⁾ ARO costs related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under the equity method for consolidated financial statement purposes.

Oil and Gas Reserve Information

In Canada, Husky’s proved crude oil, NGL and natural gas reserves are located in the provinces of Alberta, Saskatchewan, British Columbia, and offshore East Coast of Canada. Husky’s international proved reserves are located in China and Indonesia. Please note that the bitumen reserves have been separated from crude oil and prior years have been restated to account for the change in disclosure only.

	Canada												China
Reserves	Crude Oil (mmbbls)			Bitumen (mmbbls)			NGL (mmbbls)			Natural Gas (bcf)			Crude Oil (mmbbls)			Bitumen (mmbbls)		NGL (mmbbls)			Natural Gas (bcf)
Net Proved Reserves(1)(2)(3)(4)
End of Year 2014		283			360			49			1,948			6			—		10			335
Revisions		(57	)		(202	)		(12	)		(490	)		1			—		4			48
Purchases		—			—			—			7			—			—		—			—
Sales		(4	)		—			—			(6	)		—			—		—			—
Improved Recovery		1			—			—			—			—			—		—			—
Discoveries and Extensions		2			91			1			109			—			—		—			—
Production		(46	)		(21	)		(3	)		(179	)		(3	)		—		(3	)		(60	)
End of Year 2015		180			227			35			1,389			4			—		11			323
Revisions		4			42			3			(23	)		—			—		4			94
Purchases		—			3			—			8			—			—		—			—
Sales		(50	)		—			—			(58	)		—			—		—			—
Improved Recovery		—			—			—			1			—			—		—			—
Discoveries and Extensions		2			16			—			11			—			—		—			—
Production		(36	)		(34	)		(3	)		(155	)		(2	)		—		(2	)		(39	)
End of Year 2016		100			254			35			1,173			2			—		13			378
Revisions		43			375			—			214			—			—		3			52
Purchases		—			—			—			—			—			—		—			—
Sales		(10	)		—			(1	)		(283	)		—			—		—			—
Improved Recovery		20			102			—			—			—			—		—			—
Discoveries and Extensions		44			27			1			90			—			—		—			—
Production		(30	)		(41	)		(3	)		(130	)		(2	)		—		(3	)		(52	)
End of Year 2017		167			717			32			1,063			—			—		13			378
Net Proved Developed Reserves(1)(2)(3)(4)
End of Year 2014		243			113			39			1,476			6			—		10			335
End of Year 2015		167			97			32			1,116			4			—		11			323
End of Year 2016		98			104			34			986			2			—		13			378
End of Year 2017		110			154			28			735			—			—		13			378
Net Proved Undeveloped Reserves(1)(2)(3)(4)
End of Year 2014		40			247			10			472			—			—		—			—
End of Year 2015		13			130			2			273			—			—		—			—
End of Year 2016		2			150			1			187			—			—		—			—
End of Year 2017		57			563			4			328			—			—		—			—

	Indonesia(5)									Total(6)
Reserves	Crude Oil (mmbbls)		Bitumen (mmbbls)		NGL (mmbbls)		Natural Gas (bcf)			Crude Oil (mmbbls)			Bitumen (mmbbls)			NGL (mmbbls)			Natural Gas (bcf)			Total Company (mmboe)
Net Proved Reserves(1)(2)(3)(4)
End of Year 2014		—		—		5		123			289			360			64			2,406			1,113
Revisions		—		—		—		5			(56	)		(202	)		(8	)		(437	)		(339	)
Purchases		—		—		—		—			—			—			—			7			2
Sales		—		—		—		—			(4	)		—			—			(6	)		(5	)
Improved Recovery		—		—		—		—			1			—			—			—			1
Discoveries and Extensions		—		—		—		74			2			91			1			183			125
Production		—		—		—		—			(49	)		(21	)		(6	)		(239	)		(116	)
End of Year 2015		—		—		5		202			184			227			51			1,914			781
Revisions		—		—		—		6			4			42			7			77			66
Purchases		—		—		—		—			—			3			—			8			4
Sales		—		—		—		—			(50	)		—			—			(58	)		(60	)
Improved Recovery		—		—		—		—			—			—			—			1			1
Discoveries and Extensions		—		—		—		—			2			16			—			11			20
Production		—		—		—		—			(38	)		(34	)		(5	)		(194	)		(109	)
End of Year 2016		—		—		5		208			102			254			53			1,759			703
Revisions		—		—		—		(20	)		43			375			3			245			461
Purchases		—		—		—		—			—			—			—			—			—
Sales		—		—		—		—			(10	)		—			(1	)		(283	)		(58	)
Improved Recovery		—		—		—		—			20			102			—			—			122
Discoveries and Extensions		—		—		—		—			44			27			1			90			87
Production		—		—		—		(3	)		(32	)		(41	)		(6	)		(185	)		(110	)
End of Year 2017		—		—		5		185			167			717			50			1,626			1,205
Net Proved Developed Reserves(1)(2)(3)(4)
End of Year 2014		—		—		—		—			249			113			49			1,811			713
End of Year 2015		—		—		—		—			171			97			44			1,439			551
End of Year 2016		—		—		5		133			100			104			52			1,497			506
End of Year 2017		—		—		5		117			110			154			47			1,230			516
Net Proved Undeveloped Reserves(1)(2)(3)(4)
End of Year 2014		—		—		5		123			40			247			15			595			400
End of Year 2015		—		—		5		202			13			130			7			475			230
End of Year 2016		—		—		—		75			2			150			1			262			197
End of Year 2017		—		—		—		68			57			563			3			396			689

⁽¹⁾  Net reserves are the Company’s lessor royalty, overriding royalty and working interest share of the gross remaining reserves, after deduction of any crown, freehold and overriding royalties. Such royalties are subject to change by legislation or regulation and can also vary depending on production rates, selling prices and timing of initial production.

⁽²⁾  Reserves are the estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.

⁽³⁾  Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations.

⁽⁴⁾  Proved developed oil and gas reserves are proved reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped oil and gas reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

⁽⁵⁾  Husky’s beneficial interest in Indonesia and the Madura Strait Block is held by way of a 40 percent interest in Husky—CNOOC Madura Limited (“HCML”), an entity that is party to a PSC with the Government of Indonesia. Husky has entered into a unanimous shareholder agreement dated April 8, 2008 with the other shareholders of HCML that provides for joint control of HCML. International Financial Reporting Standard 11, “Joint Arrangements” (“IFRS 11”), requires Husky to follow the equity method of accounting for its investment in the Madura Strait Block. IFRS 11 focuses on the legal form of the corporate structure in which Husky’s Madura assets are held. Husky holds its interest in the Madura Strait Block through HCML and accordingly is required to use the equity method to account for this interest. As a consequence, Husky has disclosed Indonesia as a separate entity in the above disclosure because the Madura Strait Block is accounted for by the equity method of accounting.

⁽⁶⁾  In addition to the major changes to proved reserves in 2017 described under “Oil and Gas Reserves Disclosures—Reconciliation of Gross Proved Reserves” in Document A—Annual Information Form, bitumen reserves in Sunrise were economic under SEC price forecasts as of December 31, 2017 (they were uneconomic in 2015 and 2016) and account for the vast majority of the revisions in 2017.

The Company’s reserve replacement ratio⁽¹⁾for the last three years was as follows:

Net Proved Oil and Gas Reserves	2017			2016			2015
Excluding Acquisition & Divestiture		611	%		80	%		(184	)%
Including Acquisition & Divestiture		558	%		29	%		(188	)%

⁽¹⁾  Reserves replacement ratio is calculated as net reserve additions during the period divided by total production during the period. Net reserves additions include: revisions, purchases, sales, improved recovery, and discoveries and extensions. The negative reserves replacement ratio for 2015 is a result of the Sunrise bitumen reserves becoming uneconomic. SImilarly, the large positive reserves replacement ratio for 2017 is a reflection of the Sunrise bitumen reserves becoming economic again in 2017.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (unaudited)

The following information has been developed utilizing procedures prescribed by FASB Accounting Standards Codification 932, “Extractive Activities - Oil and Gas” and is based on crude oil and natural gas reserve and production volumes estimated by the Company’s reserves evaluation staff. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating Husky or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of Husky’s reserves.

The future cash flows presented below are based on average sales prices and cost rates, and statutory income tax rates in existence as of the date of the projections. It is expected that material revisions to some estimates of crude oil and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.

Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2017 was based on the New York Mercantile Exchange 2017 average natural gas cash market price of U.S. $2.98/mmbtu (2016 average - U.S. $2.48 mmbtu; 2015 average - U.S. $2.59/mmbtu) and on crude oil prices computed with reference to the 2017 average WTI spot price of U.S. $51.19/ bbl (2016 average - U.S. $42.68/bbl; 2015 average - U.S. $50.20/bbl). Natural gas prices for China and Indonesia reserves are based on various Gas Sales Agreements, are included in the AIF, and were updated as result of price negotiations with various purchasers.

Standardized Measure	Canada(1)								Other International (1)(2)						Indonesia (1)						Total (1)
(unaudited)($ millions)	2017		2016			2015			2017		2016		2015		2017		2016		2015		2017		2016			2015
Future Cash Inflows		37,720		14,423			22,014			5,707		5,967		5,044		2,016		2,378		2,174		45,443		22,768			29,232
Future Production Costs		17,843		8,378			11,358			704		548		727		917		1,140		1,075		19,464		10,066			13,160
Future Development
Costs		12,453		7,118			8,859			135		236		499		89		118		227		12,677		7,472			9,585
Future Income Taxes		2,021		(395	)		400			1,342		648		472		256		231		195		3,619		484			1,067
Future Net Cash Flows		5,403		(678	)		1,397			3,526		4,535		3,346		754		889		677		9,683		4,746			5,420
Annual 10% Discount		2,620		(1,760	)		(1,241	)		884		1,170		468		232		357		363		3,736		(233	)		(410	)
Standardized Measure of Discounted Future Net Cash Flows		2,783		1,082			2,638			2,642		3,365		2,878		522		532		314		5,947		4,979			5,830

⁽¹⁾ The schedules above are calculated using year average prices andyear-end costs, statutory income tax rates and existing proved oil and gas reserves for 2015, 2016 and 2017. The value of exploration properties and probable reserves, future exploration costs, future change in oil and gas prices and in production and development costs are excluded.

⁽²⁾ The schedule above includes China for 2015, 2016 and 2017, and Libya for 2015 and 2016.

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (unaudited)

	Canada (1)									Other International (1)(2)									Indonesia (1)									Total (1)
($ millions)	2017			2016			2015			2017			2016			2015			2017			2016			2015			2017			2016			2015
Future discounted net cash flows at beginning of year		1,082			2,638			9,820			3,365			2,878			3,070			532			314			123			4,979			5,830			13,013
Sales and transfer, net of production costs		(1,623	)		(851	)		(1,368	)		(864	)		(621	)		(1,306	)		(20	)		—			—			(2,507	)		(1,472	)		(2,674	)
Net change in sales and transfer prices, net of production costs		2,845			(2,435	)		(13,374	)		(238	)		317			(115	)		(10	)		56			—			2,597			(2,062	)		(13,489	)
Development cost incurred that reduced
Future develop. costs		1,267			705			1,990			2			114			37			33			—			39			1,302			819			2,066
Changes in estimated future development costs		(4,135	)		264			2,887			(38	)		138			3			17			108			(38	)		(4,156	)		510			2,852
Extensions, discoveries and improved recovery, net of related costs		3,006			193			1,164			—			—			—			—			—			129			3,006			193			1,293
Revisions of quantity estimates		2,573			300			(2,472	)		567			1,180			623			(64	)		23			21			3,076			1,503			(1,828	)
Accretion of discount		100			299			1,629			319			205			339			72			57			17			491			561			1,985
Sale of reserves in place		(658	)		(573	)		(93	)		—			—			—			—			—			—			(658	)		(573	)		(93	)
Purchase of reserves in place		—			40			4			—			—			—			—			—			—			—			40			4
Changes in timing of future net cash flows and other		(621	)		(128	)		(231	)		55			(790	)		323			(19	)		—			44			(585	)		(918	)		136
Net change in income taxes		(1,053	)		630			2,682			(526	)		(56	)		(96	)		(19	)		(26	)		(21	)		(1,598	)		548			2,565
Net Increase (Decrease)		1,701			(1,556	)		(7,182	)		(723	)		487			(192	)		(10	)		218			191			968			(851	)		(7,183	)
End of Year		2,783			1,082			2,638			2,642			3,365			2,878			522			532			314			5,947			4,979			5,830

⁽¹⁾  The schedules above are calculated usingyear-end average prices andyear-end costs, statutory income tax rates and existing proved oil and gas reserves for 2015, 2016, and 2017. The value of exploration properties and probable reserves, future exploration costs, future changes in oil and gas prices and in production and development costs are excluded.

⁽²⁾  The schedule above includes China for 2015, 2016 and 2017, and Libya for 2015 and 2016.