Husky Energy (CVE+A) 40-F 2013 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”. In December 2009, Husky adopted revised oil and gas reserve estimation and disclosure requirements that conformed the definition of proved reserves to the SEC Modernization of Oil and Gas Reporting rules, issued by the SEC in 2008. An accounting standards update revised the definition of proved oil and gas reserves to require that the average, first-day-of-the-month price during the 12-month period before the end of the year rather than the year-end price, must be used when estimating whether reserve quantities are economic to produce. This same 12-month average price is also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. The rules also allow for the use of reliable technologies to estimate proved oil, natural gas, and natural gas liquids (NGL) reserves if those technologies have been demonstrated to result in reliable conclusions about reserve volumes.

The unaudited supplemental information on oil and gas exploration and production activities for 2013, 2012, and 2011 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, 2013, 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, 2013
($ millions)	Canada		International		Total
Revenues, net of Royalties		5,937		220		6,157
Production and Operating Expenses		1,914		31		1,945
Depreciation, Depletion, Amortization & Impairment		2,481		19		2,500
Exploration & Evaluation Expenses		235		13		248
Earnings Before Taxes		1,307		157		1,464
Income Taxes		379		46		425
Results of Operations		928		111		1,039
	Year Ended December 31, 2012
($ millions)	Canada		International		Total
Revenues, net of Royalties		5,367		264		5,631
Production Expenses		1,798		31		1,829
Depreciation, Depletion, Amortization & Impairment		2,093		11		2,104
Exploration & Evaluation Expenses		305		45		350
Earnings before Taxes		1,170		177		1,347
Income Tax Expense		339		51		391
Results of Operations		831		126		956

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

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

($ millions)	Canada		International		Total
2013
Property Acquisition
Proved		37		—		37
Unproved		1		—		1
Exploration		554		21		575
Development		3,018		633		3,651
Total Costs Incurred		3,610		654		4,264
2012
Property Acquisition
Proved		6		—		6
Unproved		15		—		15
Exploration(1)		338		25		363
Development(2)		4,075		834		4,909
Total Costs Incurred		4,434		859		5,293
2011
Property Acquisition
Proved		792		—		792
Unproved		82		—		82
Exploration		457		266		723
Development		2,389		546		2,935
Total Costs Incurred		3,720		812		4,532

(1) Total international exploration costs of $25 million pertain entirely to Indonesia.

(2) Total international development costs of $834 million pertain to the following countries: China—$833 million and Indonesia—$1 million.

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, 2013, by the year in which the costs were incurred:

Withheld Costs (unaudited)

($ millions)	Total		2013		2012		2011		Prior to 2010
Property Acquisitions
Canada		167		11		12		144		—
International		—		—		—		—		—
Total Property Acquisitions		167		11		12		144		—
Exploration
Canada		282		—		282		—		—
International		813		538		17		235		23
Total Exploration		1,095		538		299		235		23
Development
Canada		3,469		658		662		2,053		96
International		2,585		524		939		539		583
Total Development		6,054		1,182		1,601		2,592		679
Capitalized Interest
Canada		206		95		55		24		32
International		430		171		118		62		79
Total Capitalized Interest		636		266		173		86		111
Total Withheld Costs		7,952		1,997		2,085		3,057		813

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

($ millions)	Canada			International			Total
2013
Proved Properties(1)		39,786			3,475			43,261
Unproved Properties		855			343			1,198
		40,641			3,818			44,459
Accumulated DD&A		(20,129	)		(353	)		(20,482	)
Net Capitalized Costs		20,512			3,465			23,977
2012
Proved Properties(1)		36,362			2,464			38,826
Unproved Properties		496	��		314			810
		36,858			2,778			39,636
Accumulated DD&A		(17,629	)		(318	)		(17,947	)
Net Capitalized Costs		19,229			2,460			21,689
2011
Proved Properties(1)		32,101			1,539			33,640
Unproved Properties		421			325			746
		32,522			1,864			34,386
Accumulated DD&A		(15,586	)		(312	)		(15,898	)
Net Capitalized Costs		16,936			1,552			18,488

⁽¹⁾ Capitalized costs related to proved properties include the ARO. The ARO for the years presented were as follows:

($ millions)	Canada		International		Total
2013		2,391		161		2,552
2012		2,363		129		2,492
2011		1,369		20		1,389

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, Indonesia and Libya.

	Canada									International									Total
Reserves	Crude Oil (mmbbls)			NGL (mmbbls)			Natural Gas (bcf)			Crude Oil (mmbbls)			NGL (mmbbls)			Natural Gas (bcf)			Crude Oil (mmbbls)			NGL (mmbbls)			Natural Gas (bcf)			Total Company (mmboe)
Net Proved Reserves(1) (2) (3) (4)
End of Year 2010		540			42			1,587			6			5			147			546			47			1,734			882
Revisions		(1	)		—			34			(1	)		—			(10	)		(2	)		—			24			2
Purchases		21			16			342			—			—			—			21			16			342			94
Sales		(2	)		—			(2	)		—			(1	)		(29	)		(2	)		(1	)		(31	)		(8	)
Improved Recovery		13			—			1			—			—			—			13			—			1			13
Discoveries and Extensions		84			3			75			—			—			—			84			3			75			99
Production		(63	)		(2	)		(213	)		(2	)		—			—			(65	)		(2	)		(213	)		(102	)
End of Year 2011		592			59			1,824			3			4			108			595			63			1,932			980
Revisions		29			(4	)		(357	)		4			(1	)		—			33			(5	)		(357	)		(30	)
Purchases		—			—			—			—			—			—			—			—			—			—
Sales		(1	)		—			—			—			—			—			(1	)		—			—			(1	)
Improved Recovery		16			—			—			—			—			—			16			—			—			16
Discoveries and Extensions		29			6			140			1			7			271			30			13			411			111
Production		(63	)		(3	)		(190	)		(2	)		—			—			(65	)		(3	)		(190	)		(100	)
End of Year 2012		602			58			1,417			6			10			379			608			68			1,796			976
Revisions		20			(2	)		144			3			1			3			23			(1	)		147			80
Purchases		1			—			1			—			—			—			1			—			1			1
Sales		—			—			(3	)		—			—			—			—			—			(3	)		(1	)
Improved Recovery		7			—			—			—			—			—			7			—			—			7
Discoveries and Extensions		75			5			228			0			1			21			75			6			249			89
Production		(67	)		(3	)		(174	)		(2	)		—			—			(69	)		(3	)		(174	)		(101	)
End of Year 2013		638			58			1,613			7			12			403			645			70			2,016			1,051
Net Proved Developed Reserves (1)(2)(3)(4)
End of Year 2010		301			34			1,327			6			—			—			307			34			1,327			562
End of Year 2011		320			50			1,567			3			—			—			323			50			1,567			635
End of Year 2012		331			50			1,191			6			—			—			337			50			1,191			585
End of Year 2013		332			51			1,247			7			7			275			339			58			1,522			651
Net Proved Undeveloped Reserves(1)(2)(3)(4)
End of Year 2010		239			8			260			—			5			147			239			13			407			320
End of Year 2011		272			9			257			—			4			108			272			13			365			345
End of Year 2012		271			8			226			—			10			379			271			18			605			391
End of Year 2013		306			7			366			—			5			128			306			12			494			400

⁽¹⁾  Net reserves are the Company’s lesser 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.

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

Net Proved Oil and Gas Reserves	2013			2012			2011
Excluding Acquisition & Divestiture		174	%		96	%		112	%
Including Acquisition & Divestiture		174	%		96	%		196	%

⁽¹⁾ Reserve replacement ratio is calculated as net reserve additions during the period divided by total production during the period. Net reserve additions include: revisions, purchases, sales, improved recovery, and discoveries and extensions.

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, 2013 was based on the NYMEX 2013 average natural gas cash market price of U.S. $3.67/mmbtu (2012 average—U.S. $2.78/mmbtu; 2011 average—U.S. $4.15/mmbtu) and on crude oil prices computed with reference to the 2013 average WTI spot price of U.S. $97.48/bbl (2012 average—U.S. $95.38/bbl; 2011 average—U.S. $95.95/bbl).

Standardized Measure (unaudited) ($ millions)	Canada(1)						International(1)						Total(1)
	2013		2012		2011		2013		2012		2011		2013		2012		2011
Future Cash Inflows		47,890		43,058		50,824		6,331		5,850		1,510		54,221		48,908		52,334
Future Production Costs		18,443		15,803		18,342		1,261		1,099		503		19,704		16,902		18,845
Future Development Costs		11,150		8,138		7,932		656		1,293		161		11,806		9,431		8,093
Future Income Taxes		4,682		4,724		6,286		755		670		282		5,437		5,394		6,568
Future Net Cash Flows		13,615		14,393		18,264		3,659		2,788		564		17,274		17,181		18,828
Annual 10% Discount Factor		5,119		5,747		8,217		660		724		199		5,779		6,471		8,416
Standardized Measure of Discounted Future Net Cash Flows		8,496		8,646		10,047		2,999		2,064		365		11,495		10,710		10,412

⁽¹⁾ The schedules above are calculated using year average prices and year-end costs, statutory income tax rates and existing proved oil and gas reserves for 2011, 2012 and 2013. 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.

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

Reserves (unaudited)

	Canada(1)									International(1)									Total(1)
($ millions)	2013			2012			2011			2013			2012			2011			2013			2012			2011
Present Value at January 1		8,646			10,047			7,791			2,064			365			354			10,710			10,412			8,145
Sales and Transfers, net of Production Costs		(3,980	)		(3,538	)		(4,239	)		(189	)		(235	)		(216	)		(4,169	)		(3,773	)		(4,455	)
Net Change in Sales and Transfer Prices, net of Development and Production Costs		975			(1,353	)		3,281			(87	)		(15	)		266			888			(1,368	)		3,547
Development Cost Incurred that Reduced Future Development Costs		3,380			3,093			2,500			650			733			7			4,030			3,826			2,507
Changes in Estimated Future Development Costs		(3,941	)		(2,234	)		(1,921	)		47			(1,551	)		26			(3,894	)		(3,785	)		(1,895	)
Extensions, Discoveries and Improved Recovery, net of Related Costs		1,281			937			1,601			203			2,774			10			1,484			3,711			1,611
Revisions of Quantity Estimates		1,169			(460	)		156			237			426			(47	)		1,406			(34	)		109
Accretion of Discount		939			1,194			908			262			(101	)		55			1,201			1,093			963
Sale of Reserves in Place		(6	)		(12	)		(28	)		—			—			(59	)		(6	)		(12	)		(87	)
Purchase of Reserves in Place		25			9			1,096			—			—			—			25			9			1,096
Changes in Timing of Future Net Cash Flows and Other		158			320			(358	)		(107	)		(4	)		(20	)		51			316			(378	)
Net Change in Income Taxes		(150	)		643			(740	)		(81	)		(328	)		(11	)		(231	)		315			(751	)
Net Increase (Decrease)		(150	)		(1,401	)		2,256			935			1,699			11			785			298			2,267
Present Value at December 31		8,496			8,646			10,047			2,999			2,064			365			11,495			10,710			10,412

⁽¹⁾ The schedules above are calculated using year-end average prices and year-end costs, statutory income tax rates and existing proved oil and gas reserves for 2011, 2012, and 2013. 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.