Husky Energy Delivers Solid Results in 2013

CALGARY, ALBERTA--(Marketwired - Feb. 12, 2014) - Husky Energy (TSX:HSE) recorded a four percent increase in cash flow from operations in 2013 during a period of significant commodity price volatility, supported by a steady increase in production, strong operational performance and a focused integration strategy.

"From the acceleration of our heavy oil thermal program to new oil discoveries in the Atlantic Region, we have laid the groundwork to support our future growth objectives," said CEO Asim Ghosh. "We are building momentum as we put the final touches on the Liwan Gas Project and prepare to start up the Sunrise Energy Project in the second half of this year."

The 3,500 barrels per day (bbls/day) Sandall heavy oil thermal project has achieved first oil. The Company continues to advance towards its accelerated heavy oil thermal production target of 55,000 bbls/day in 2016 and recently sanctioned two 10,000 bbls/day thermal developments at Edam East and Vawn.

In the Asia Pacific Region, commissioning is underway at the Liwan Gas Project following the successful installation of deepwater flowlines in the South China Sea, approximately 300 kilometres southeast of the Hong Kong Special Administrative Region.

Cash flow from operations for the year rose to $5.2 billion, up from $5.0 billion in 2012. Net earnings were $1.8 billion, reflecting a non-cash impairment charge of $204 million after tax on dry gas properties in Western Canada. Excluding the impairment, net operating earnings were $2 billion, comparable to 2012. The impairment was driven by a decrease in gas price forecasts in future years.

Annual Upstream production was within guidance at 312,000 barrels of oil equivalent per day (boe/day), up from 301,500 boe/day in 2012. This included growth in heavy oil thermal production and liquids-rich gas play activity, offset by a continuing reduction in dry gas production.

The Company continued to add more proved reserves compared to production in 2013 from crude oil and liquids-rich natural gas. The reserve replacement ratio for 2013, excluding economic factors, was 166 percent (164 percent including economic factors). At year-end, Husky had total proved reserves before royalties of 1.3 billion boe, probable reserves of 1.9 billion boe and best estimate contingent resources of 13.2 billion boe.

Reserves growth has consistently outpaced production, with an average proved reserves replacement ratio (excluding economic factors) over the past three years of 172 percent. Including economic factors, the average proved three-year reserves replacement ratio was 154 percent, ahead of the five-year average target of 140 percent per year.

Annual Performance Highlights:

• Annual production averaged 312,000 boe/day, up from approximately 301,500 boe/day in 2012.
• Cash flow from operations over the year was $5.2 billion, or $5.31 per share (diluted), an increase from $5.0 billion, or $5.13 per share (diluted) in 2012.
• Net earnings for the year were $1.8 billion, or $1.85 per share (diluted), compared to $2.0 billion or $2.06 per share (diluted) in 2012. This reflects a non-cash impairment charge of $204 million after tax, associated with dry gas assets in Western Canada. Net operating earnings were $2.0 billion, or $2.07 per share (diluted).
• Downstream throughputs averaged 317,000 bbls/day over the year compared to 327,000 bbls/day in 2012, reflecting scheduled maintenance at the Company's refineries in Lloydminster and Prince George and a major turnaround at the Lloydminster Upgrader.
• The reserve replacement ratio for 2013, excluding economic factors, was 166 percent (164 percent including economic factors.) Reserves growth has consistently outpaced production, with an average proved reserves replacement ratio (excluding economic factors) over the past three years of 172 percent.

Foundation Highlights:

• Achieved first oil at the 3,500 bbls/day Sandall thermal project in early 2014.
• Advanced the 10,000 bbls/day Rush Lake commercial thermal development towards first production in the second half of 2015.
• Sanctioned two 10,000 bbls/day thermal projects at Edam East and Vawn with production expected in 2016.
• Accelerated development of the Ansell liquids-rich gas resource play.
• Commissioned a kero-hydrotreater at the Lima refinery to increase distillate capacity and product flexibility.
• Installed a new recycle gas compressor at the partner-operated refinery in Toledo to improve performance.
• Further improved Downstream flexibility by adding additional storage capacity at Hardisty.
• Sanctioned a project at the Husky Lima Refinery to provide flexibility for the processing of up to 40,000 bbls/day of heavy oil by 2017.

Growth Pillar Highlights:

• Final installation and commissioning of major offshore infrastructure at the Liwan Gas Project, including nine subsea production wells and the shallow water platform. The onshore gas terminal is also in commissioning.
• Commissioning is underway on six of eight well pads at the Sunrise Energy Project, with startup planned in the second half of 2014.
• Brought a fifth oil production well online at the North Amethyst satellite tie-back.
• Began drilling a Hibernia formation well at North Amethyst.
• Discovered two new oil fields at Bay du Nord and Harpoon in the Atlantic Region and secured a rig to accelerate appraisal of these discoveries and the previously announced Mizzen field.
• Signed a benefits agreement with the Government of Newfoundland and Labrador for the West White Rose field and commenced building a graving dock to support the construction of a wellhead platform for the field and other nearby resources.

FINANCIAL AND OPERATIONAL HIGHLIGHTS

		Three Months Ended			Twelve Months Ended
		Dec. 31 2013	Sept. 30 2013	Dec. 31 2012	Dec. 31 2013	Dec. 31 2012
1) Daily Production, before royalties
	Total Equivalent Production (mboe/day)	308	309	319	312	302
	Crude Oil and NGLs (mbbls/day)	224	224	232	227	209
	Natural Gas (mmcf/day)	504	506	524	513	554
2) Total Upstream Netback ($/boe) (1)		34.29	46.15	35.99	37.72	35.14
3) Refinery and Upgrader Throughput (mbbls/day)		324	300	335	317	327
4) Cash Flow from Operations(2) (Cdn $ millions)		1,143	1,347	1,414	5,222	5,010
	Per Common Share - Basic ($/share)	1.16	1.37	1.44	5.31	5.13
	Per Common Share - Diluted ($/share)	1.16	1.37	1.44	5.31	5.13
5) Net Earnings (Cdn $ millions)		177	512	474	1,829	2,022
	Per Common Share - Basic ($/share)	0.18	0.52	0.48	1.85	2.06
	Per Common Share - Diluted ($/share)	0.18	0.52	0.48	1.85	2.06
6) Adjusted Net Earnings(2) (Cdn $ millions)		412	544	487	2,113	2,010
	Per Common Share - Basic ($/share)	0.42	0.55	0.50	2.15	2.06
	Per Common Share - Diluted ($/share)	0.42	0.55	0.50	2.15	2.06
7) Capital Investment, including acquisitions (Cdn $ millions)		1,537	1,407	1,473	5,028	4,701
8) Dividend
	Per Common Share ($/share)	0.30	0.30	0.30	1.20	1.20

(1) Upstream Netback includes results from Upstream Exploration and Production and excludes Upstream Infrastructure and Marketing.

(2) Cash Flow from Operations and Adjusted Net Earnings are non-GAAP measures. Refer to the Q4 MD&A, Section 11 for reconciliation.

Average annual production was 312,000 boe/day, up from 301,500 boe/day in 2012. This reflected increased heavy oil thermal volumes and liquids-rich gas play activity offset by a deliberate reduction in dry gas production, unplanned maintenance on the partner-operated Terra Nova FPSO (Floating Production, Storage and Offloading) vessel and ongoing third-party production constraints in Western Canada. Fourth quarter production averaged 308,300 boe/day compared to 319,300 boe/day a year ago.

Average West Texas Intermediate (WTI) pricing over the year was U.S. $97.97 per barrel compared to U.S. $94.21 in 2012. Average realized liquids pricing was $78.12 per barrel compared to $75.50 in 2012.

U.S. refining Chicago market crack spreads averaged U.S. $21.30 per barrel in 2013, compared to U.S. $27.63 a year ago. U.S. realized refining margins over the year were $15.06 per barrel, compared to $17.48 in 2012.

In the fourth quarter, WTI prices averaged U.S. $97.46 per barrel compared to U.S. $88.18 a year ago. Average realized liquids pricing was $73.06 per barrel in the fourth quarter, compared to $72.17 a year ago.

U.S. refining Chicago market crack spreads averaged U.S. $11.91 per barrel in the fourth quarter, a significant reduction from U.S. $28.00 in the same period in 2012, while the realized refining margin averaged $6.94 per barrel compared to $16.19 a year ago.

"The focused integration of our business again helped to offset significant commodity price volatility in 2013, including persistent pricing and location challenges," said CFO Alister Cowan.

KEY AREA SUMMARY

THE FOUNDATION BUSINESS

• Heavy Oil

The Company is continuing to transform its heavy oil business through a growing portfolio of long-life thermal developments. Annual thermal production increased 42 percent to more than 37,000 bbls/day in 2013 compared to 26,000 bbls/day in 2012.

Steaming commenced at the 3,500 bbls/day Sandall thermal project, with first oil achieved in early 2014.

Design and site work continued at the 10,000 bbls/day commercial thermal project at Rush Lake, with steady results from the two-well pair pilot. First oil is anticipated in the second half of 2015.

Building on the success of its existing thermal projects, two new 10,000 bbls/day thermal developments were sanctioned at Edam East and Vawn, with first oil planned for 2016.

Husky completed its planned heavy oil drilling program for 2013, drilling 140 horizontal wells and 228 Cold Heavy Oil Production with Sand (CHOPS) wells over the year. In the fourth quarter, 49 horizontal wells and 76 CHOPS wells were drilled.

• Western Canada

The rejuvenation of Western Canada operations is focused on de-risking the Company's oil and liquids-rich gas resource portfolio and reducing costs through improved well design and management. Overall resource play production has increased more than 80 percent since 2010.

More than 95 percent of all wells drilled targeted oil and liquids-rich gas production as the Company reduced its dry gas volumes in favour of these higher return resource plays.

Gas Resource Plays

A four-rig program at the multi-zone Ansell liquids-rich gas play produced strong results. In total, 25 wells were drilled and 30 completed in 2013.

Production began in the fourth quarter on a four-well pad at Kaybob in the Duvernay play, with results as anticipated.

Oil Resource Plays

A total of 101 wells were drilled and 96 wells completed across the portfolio in 2013, with drilling activities focused on the near-term Bakken, Viking and Cardium oil resource plays.

• Downstream

Targeted investment to improve the flexibility of crude feedstocks, product range and market access continues to capture value. Throughput averaged 317,000 bbls/day, reflecting scheduled turnarounds at the Company's upgrader and refineries in Lloydminster and Prince George.

Construction is underway on two 300,000 barrel tanks at Hardisty, Alberta to further improve storage capability.

A new 20,000 bbls/day kero-hydrotreater installed at the Lima refinery has provided increased capacity to produce distillate and greater flexibility to swing production between on-road diesel and jet fuel.

At the partner-operated refinery in Toledo, Ohio, a new recycle gas compressor is being installed in the existing hydrotreater to improve operational integrity and plant performance, with completion scheduled for later in 2014.

The Company has sanctioned a project at the Husky Lima Refinery to provide flexibility for the processing of up to 40,000 barrels per day of heavy crude feedstock from Western Canada starting in 2017. The investment supports the Company's growing heavy oil thermal business in Western Canada, where production is anticipated to reach 55,000 bbls/day in 2016.

GROWTH PILLARS

• Asia Pacific Region

The Liwan Gas Project is nearing production and commissioning of the shallow water platform and gas plant is underway.

Major milestones in 2013 included the installation of the 30,000-tonne topsides onto the shallow water jacket in the South China Sea, construction of the onshore gas terminal and completion of all nine subsea deepwater production wells approximately 75 kilometres from the platform. The final components of the deepwater infrastructure for the Liwan 3-1 field have been installed and commissioning is proceeding.

The Liuhua 34-2 field is scheduled to be tied into the producing Liwan deepwater facilities during a six to eight-week period in the second half of 2014. Negotiations for a gas sales contract for the Liuhua 29-1 field are in progress with first production expected in the 2016-2017 timeframe.

In the Madura Strait block offshore Indonesia, engineering and procurement has commenced on the shallow water platform infrastructure at the BD field and a tender for an FPSO is awaiting final government approval.

Negotiations for a gas sales contract for the combined MDA/MBH development on the Madura Strait block are progressing, with first production anticipated in the late 2016-early 2017 timeframe.

A new natural gas discovery made on the block in the fourth quarter is now being evaluated, along with four previous discoveries made in 2012. Husky has a 50 percent interest in the MBF discovery, which is located west of the MBH field.

Elsewhere in the Asia Pacific Region, the Company began a two-dimensional seismic survey on the Company-operated exploration block off the southwest coast of Taiwan. The remainder of the work is due to be completed in 2014.

• Oil Sands

The Sunrise Energy Project was 85 percent complete at the end of the year and is advancing as planned towards startup in the second half of 2014.

Initial engineering is underway for the next phase of Sunrise. Subject to approvals, the second phase of the Central Plant Facility is expected to be developed in two stages, each with a capacity of 70,000 bbls/day of production, bringing total capacity at Sunrise to 200,000 bbls/day (100,000 bbls/day net to Husky).

• Atlantic Region

Husky made good progress in developing its three satellite extensions at the White Rose area as it continued to advance near, medium and long-term opportunities in the Jeanne d'Arc Basin and Flemish Pass offshore Newfoundland and Labrador.

A fifth production well at North Amethyst, the first multi-lateral well in the White Rose field, was brought online in the fourth quarter with production averaging 14,000 bbls/day (net to Husky). Drilling began on a deeper Hibernia formation well below the main field, with production anticipated to commence later in 2014.

At the South White Rose field, gas injection is planned for the first quarter of 2014 with first oil expected later in the year. At the West White Rose field, a benefits agreement was signed with the provincial government. Construction has commenced on a graving dock to support wellhead platform construction, with first production scheduled for the 2017 timeframe subject to final approvals.

Two significant oil discoveries were made at Harpoon and Bay du Nord in the Flemish Pass Basin in 2013. The Company and its partner have secured a drilling rig to accelerate appraisal plans for these discoveries and the previously announced Mizzen field.

CORPORATE DEVELOPMENTS

The Board of Directors has declared a quarterly dividend of $0.30 (Canadian) per share on its common shares for the three-month period ending December 31, 2013. The dividend will be payable on April 1, 2014 to shareholders of record at the close of business on March 13, 2014.

The Board has decided to discontinue the payment of dividends by way of the issuance of common shares. The change is effective as of today's fourth quarter dividend declaration.

A regular quarterly dividend on the 4.45 percent Cumulative Redeemable Preferred Shares, Series 1 (the "Series 1 Preferred Shares") will be paid for the period January 1, 2014 to March 31, 2014. The dividend of $0.27813 per Series 1 Preferred Share will be payable on March 31, 2014 to holders of record at the close of business on March 13, 2014.

CONFERENCE CALL

A conference call will take place on Wednesday, February 12 at 9 a.m. Mountain Time (11 a.m. Eastern Time) to discuss Husky's year-end and fourth quarter results. To listen live, please call one of the following numbers:

Canada and U.S. Toll Free:	1-800-319-4610
Outside Canada and U.S.:	1-604-638-5340

CEO Asim Ghosh, COO Rob Peabody, CFO Alister Cowan and Downstream Senior VP Bob Baird will participate in the call. To listen to a recording of the call, available at 11 a.m. Mountain Time on February 12, please call one of the following numbers:

Canada and U.S. Toll Free:	1-800-319-6413
Outside Canada and U.S.:	1-604-638-9010

Passcode:	2658 followed by the # sign
Duration:	Available until March 16, 2014

An audio webcast of the conference call will be available for approximately 90 days at www.huskyenergy.com under Investor Relations.

Husky Energy is one of Canada's largest integrated energy companies. It is headquartered in Calgary, Alberta, Canada and is publicly traded on the Toronto Stock Exchange under the symbol HSE and HSE.PR.A. More information is available at www.huskyenergy.com

FORWARD-LOOKING STATEMENTS

Certain statements in this news release 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 news release are forward-looking and not historical facts.

Such forward-looking statements are based on the Company's current expectations, estimates, projections and assumptions that were made by the Company in light of its experience and its perception of historical trends. Further, such forward-looking statements are subject to risks, uncertainties and other factors, some of which are beyond the Company's control and difficult to predict. Accordingly, these factors could cause actual results or outcomes to differ materially from those expressed or projected in the forward-looking statements.

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", "estimated", "intend", "plan", "projection", "could", "aim", "vision", "goals", "objective", "target", "schedules" and "outlook"). In particular, forward-looking statements in this news release 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;
• with respect to the Company's Asia Pacific Region: scheduled timing and duration of tie-in of the Liuhua 34-2 field to the Liwan deepwater facilities; anticipated timing of first production from the Liuhua 29-1 field; scheduled timing of completion of 2D seismic work on the Company's offshore Taiwan exploration block;
• with respect to the Company's Atlantic Region: anticipated timing of first production from a deeper Hibernia formation well at the Company's North Amethyst field; planned timing of gas injection and expected timing of first production from the Company's South White Rose field; scheduled timing of first production at the Company's West White Rose field;
• with respect to the Company's Oil Sands properties: anticipated timing of startup of the Company's Sunrise Energy Project; anticipated development plan and anticipated daily production capacity for the next phase of the Company's Sunrise Energy Project;
• with respect to the Company's Heavy Oil properties: the Company's heavy oil thermal production target by 2016; anticipated timing of first production from the Company's Rush Lake commercial thermal development; anticipated timing of first production from the Company's Edam East and Vawn thermal projects; and
• with respect to the Company's Downstream operating segment: anticipated timing of completion and processing volumes for a flexibility project at the Company's Lima Refinery; anticipated timing of completion of upgrades at the partner-operated Toledo Refinery.

In addition, statements relating to "reserves" and "resources" are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves or resources described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of reserves and resources and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary from reserve, resource and production estimates.

Although the Company believes that the expectations reflected by the forward-looking statements presented in this news release 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, regulators and other sources.

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 Husky.

The Company's Annual Information Form for the year ended December 31, 2012 and other documents filed with securities regulatory authorities (accessible through the SEDAR website www.sedar.com and the EDGAR website www.sec.gov) describe the risks, material assumptions and other factors that could influence actual results and are incorporated herein by reference.

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. 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 its assessment of the future considering all information then available.

Non-GAAP Measures

This news release contains certain terms which do not have any standardized meaning prescribed by IFRS and are therefore 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. These terms include:

• Cash Flow from Operations, 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. Cash flow from operations is presented in the Company's financial reports to assist management and investors in analyzing operating performance by business in the stated period. Cash flow from operations equals net earnings plus items not affecting cash which include accretion, depletion, depreciation and amortization, exploration and evaluation expense, deferred income taxes, foreign exchange, gain or loss on sale of property, plant, and equipment and other non‐cash items.
• Net Operating Earnings is a non-GAAP measure comprised of net earnings excluding extraordinary and non-recurring items such as impairment of property, plant and equipment which is not considered indicative of the Company's on-going financial performance. Net operating earnings is a complementary measure used in assessing Husky's financial performance through providing comparability between periods.

Disclosure of Oil and Gas Information

Unless otherwise stated, reserve and resource estimates in this news release have an effective date of December 31, 2013 and represent Husky's share. Unless otherwise noted, historical production numbers given represent Husky's share.

The Company uses the terms barrels of oil equivalent ("boe"), which is calculated on an energy equivalence basis whereby one barrel of crude oil is equivalent to six thousand cubic feet of natural gas. Readers are cautioned that the term boe may be misleading, particularly if used in isolation. This measure is primarily applicable at the burner tip and does not represent value equivalence at the wellhead.

Reserve replacement ratios for a given period are determined by taking the Company's incremental proved reserve additions for that period divided by the Company's upstream gross production for the same period. Forecast reserve replacement ratios for a given period are calculated by taking the forecast proved reserve additions for those periods divided by the forecast gross production for the same periods.

The Company has disclosed best-estimate contingent resources of 13.2 billion boe, which is comprised of 12.0 billion bbls of crude oil and 6.5 tcf of natural gas. Of the total, 11.0 billion boe is economic at year-end 2013. Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters, or a lack of markets. There is no certainty that it will be commercially viable to produce any portion of the contingent resources.

Contingent resources are reported as the working interest volumes and Husky's working interest varies in the properties. The properties assigned contingent resources are Western Canada gas resource plays and EOR projects, Lloydminster thermal projects, N.W.T. conventional gas, oil sands, East Coast offshore and Asia Pacific gas.

Best estimate as it relates to resources is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Estimates of contingent resources have not been adjusted for risk based on the chance of development.

There is no certainty as to the timing of such development. For movement of resources to reserves categories, all projects must have an economic depletion plan and may require, among other things: (i) additional delineation drilling for unrisked contingent resources; (ii) regulatory approvals; and (iii) Company and partner approvals to proceed with development.

Specific contingencies preventing the classification of contingent resources at the Company's oil sands properties as reserves include further reservoir studies, delineation drilling, facility design, preparation of firm development plans, regulatory applications and company approvals. Development is also contingent upon successful application of SAGD and/or Cyclic Steam Stimulation (CSS) technology in carbonate reservoirs at Saleski, which is currently under active development. Positive and negative factors relevant to the estimate of oil sands resources include a higher level of uncertainty in the estimates as a result of lower core-hole drilling density.

Specific contingencies preventing the classification of contingent resources at the Company's Atlantic Region discoveries as reserves include additional exploration and delineation drilling, well testing, facility design, preparation of firm development plans, regulatory applications, Company and partner approvals. Positive and negative factors relevant to the estimate of Atlantic Region resources include water depth and distance from existing infrastructure.

Note to U.S. Readers

The Company reports its reserves and resources information in accordance with Canadian practices and specifically in accordance with National Instrument 51-101, "Standards of Disclosure for Oil and Gas Disclosure", adopted by the Canadian securities regulators. Because the Company is permitted to prepare its reserves and resources information in accordance with Canadian disclosure requirements, it uses certain terms in this news release, such as "best estimate contingent resources" that U.S. oil and gas companies generally do not include or may be prohibited from including in their filings with the SEC.