Husky Energy Delivers Solid Results in 2013

Husky Energy Delivers Solid Results in 2013 
CALGARY, ALBERTA -- (Marketwired) -- 02/12/14 -- 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  


 
                                                               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

 
(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.
Contacts:
Investor Inquiries:
Dan Cuthbertson
Manager, Investor Relations
Husky Energy Inc.
403-523-2395 
Media Inquiries:
Mel Duvall
Manager, Media & Issues
Husky Energy Inc.
403-513-7602
 
 
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