Husky Energy Delivers Solid Results in 2013

NEWS RELEASE TRANSMITTED BY Marketwired 
FOR: Husky Energy Inc. 
TSX SYMBOL:  HSE 
FEBRUARY 12, 2014 
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: 
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--  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.  
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Foundation Highlights: 
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--  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. 
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Growth Pillar Highlights: 
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--  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. 
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FINANCIAL AND OPERATIONAL HIGHLIGHTS  
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Twelve Months 
Three Months Ended             Ended 
Dec. 31 Sept. 30  Dec. 31  Dec. 31  Dec. 31 
2013     2013     2012     2013     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           1.16     1.37     1.44     5.31     5.13
  ($/share)                                                                 
 Per Common Share - Diluted                                                 
  ($/share)                         1.16     1.37     1.44     5.31     5.13
5) Net Earnings (Cdn $               177      512      474    1,829    2,022
 millions)                                                                   
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)          412      544      487    2,113    2,010
 (Cdn $ millions)                                                            
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 
/T/ 
(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 
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--  Heavy Oil 
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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. 
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--  Western Canada 
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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.  
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--  Downstream 
/T/ 
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 
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--  Asia Pacific Region 
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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. 
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--  Oil Sands 
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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). 
/T/ 
--  Atlantic Region 
/T/ 
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: 
/T/ 
Canada and U.S. Toll Free:         1-800-319-4610                 
Outside Canada and U.S.:           1-604-638-5340                  
/T/ 
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: 
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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  
/T/ 
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:  
/T/ 
--  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. 
/T/ 
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: 
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--  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.  
/T/ 
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. 
-30-
FOR FURTHER INFORMATION PLEASE CONTACT: 
Investor Inquiries:
Dan Cuthbertson
Manager, Investor Relations
Husky Energy Inc.
403-523-2395
or
Media Inquiries:
Mel Duvall
Manager, Media & Issues
Husky Energy Inc.
403-513-7602 
INDUSTRY:  Energy and Utilities - Oil and Gas  
SUBJECT:  ERN 
-0-
-0- Feb/12/2014 12:00 GMT
 
 
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