Steady Progress for Husky Energy in Third Quarter

Steady Progress for Husky Energy in Third Quarter 
CALGARY, ALBERTA -- (Marketwired) -- 10/24/13 -- Husky Energy
(TSX:HSE) continued to drive forward its growth plans in the third
quarter as it announced a significant oil discovery offshore
Newfoundland and Labrador and advanced the landmark Liwan Gas Project
in the Asia Pacific Region closer to first production. 
"Our business continues to deliver consistent results across the
board," said CEO Asim Ghosh. "We are hitting our targets and making
steady progress towards executing our important milestones." 
Cash flow from operations was approximately $1.35 billion, compared
to $1.27 billion in the third quarter of 2012. Net earnings of $512
million were comparable to $526 million in the same period last year. 
Total Upstream production was approximately 309,000 barrels of oil
equivalent per day (boe/day). This takes into account the scheduled
six-day routine maintenance program on the SeaRose Floating
Production, Storage and Offloading (FPSO) vessel as well as an
ongoing planned reduction in dry gas production. Total oil and
liquids production was 224,000 barrels per day (bbls/day), compared
to 194,000 bbls/day in the third quarter of 2012, which reflects the
planned SeaRose FPSO turnaround a year ago and increased heavy oil
thermal production. 
Downstream refineries and the Lloydminster Upgrader realized average
throughputs of about 300,000 barrels per day (bbls/day), which takes
into account a scheduled 45-day shutdown of the Upgrader for routine
maintenance. 
The Liwan Gas Project is more than 95 percent complete with
commissioning work underway on the central platform and the onshore
gas plant. The project is on schedule for first production in the
coming months.  
Husky and its partner continue to assess the commercial potential of
the recent discoveries at Bay du Nord, Harpoon and Mizzen in the
Atlantic Region. Husky has a 35 percent working interest in all three
discoveries. 
Highlights Include: 


 
--  Net earnings were $512 million, or $0.52 per share (diluted), compared
    to $526 million, or $0.53 per share (diluted) in the third quarter of
    2012. 
--  Cash flow from operations was $1.35 billion, or $1.37 per share
    (diluted), compared with $1.27 billion, or $1.29 per share (diluted) in
    the third quarter of 2012. 
--  Total Upstream production was approximately 309,000 boe/day, up from
    approximately 285,000 boe/day in the third quarter of 2012. 
--  Construction is nearly 95 percent complete at the 3,500 bbls/day Sandall
    heavy oil thermal project, with first production anticipated in the
    first half of 2014. 
--  Four drilling rigs are dedicated to the Ansell liquids-rich gas resource
    play development. 
--  Field facility construction for Phase 1 of the Sunrise Energy Project is
    in the final stages with the overall project approximately 80 percent
    complete and on track to start up in the second half of 2014. 
--  A benefits agreement was concluded with the Government of Newfoundland
    and Labrador for the West White Rose development, and detailed
    engineering is proceeding for a fixed wellhead platform.

 
FINANCIAL AND OPERATIONAL HIGHLIGHTS  


 
                                Three Months Ended        Nine Months Ended 
                           Sept. 30  June 30   Sept. 30  Sept. 30  Sept. 30 
                             2013      2013      2012      2013      2012   
1) Daily Production,                                                        
 before royalties                                                           
 Total Equivalent                                                           
  Production (mboe/day)       309       310       285       313       296   
 Crude Oil and NGLs                                                         
  (mbbls/day)                 224       226       194       227       202   
 Natural Gas (mmcf/day)       506       505       545      515.8      564   
2) Total Upstream Netback                                                   
 ($/boe) (1)                 46.15     38.32     30.08     38.86     34.83  
3) Refinery and Upgrader                                                    
 Throughput (mbbls/day)       300       317       328       314       325   
4) Cash Flow from                                                           
 Operations(2) (Cdn $                                                       
 millions)                   1,347     1,449     1,271     4,079     3,596  
 Per Common Share - Basic    1.37      1.47      1.29      4.15      3.69   
  ($/share)                                                                 
 Per Common Share -                                                         
  Diluted ($/share)          1.37      1.47      1.29      4.15      3.69   
5) Net Earnings (Cdn $                                                      
 millions)                    512       605       526      1,652     1,548  
 Per Common Share - Basic                                                   
  ($/share)                  0.52      0.61      0.53      1.67      1.58   
 Per Common Share -                                                         
  Diluted ($/share)          0.52      0.59      0.53      1.66      1.57   
6) Adjusted Net                                                             
 Earnings(2) (Cdn $                                                         
 millions)                    544       610       512      1,701     1,523  
 Per Common Share - Basic                                                   
  ($/share)                  0.55      0.62      0.52      1.73      1.56   
 Per Common Share -                                                         
  Diluted ($/share)          0.55      0.62      0.52      1.73      1.56   
7) Capital Investment,                                                      
 including acquisitions                                                     
 (Cdn $ millions)            1,407      932      1,252     3,491     3,228  
8) Dividend                                                                 
 Per Common Share                                                           
  ($/share)                  0.30      0.30      0.30      0.90      0.90   
                                                                            
(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 Q3 MD&A, Section 11 for reconciliation.          

 
Third quarter production of approximately 309,000 boe/day reflected a
planned six-day shutdown of the SeaRose FPSO in July to tie in
equipment for the South White Rose satellite extension. Third-party
infrastructure outages and downtime in Western Canada continued to
create production constraints that are anticipated to last through
the end of the year.  
The partner-operated Terra Nova FPSO began an 11-week maintenance
offstation late in the quarter. Husky has a 13 percent working
interest in Terra Nova and together with outages earlier in the year,
the cumulative annual production impact is approximately 2,100
bbls/day. 
The Lloydminster Upgrader successfully concluded a planned turnaround
in mid-October and has resumed normal production.  
"Through the year, we have continued to redirect capital from dry gas
to higher-netback resource play opportunities, which changes our
previous annual guidance range for gas to a range of 500 and 520
million cubic feet per day," said CFO Alister Cowan. "Even with the
impacts from the Terra Nova outages and planned lower dry gas
production, we still expect to stay within our overall guidance
range." 
In the Downstream business, significantly lower market crack spreads
had an impact on refining margins in the third quarter. 
Average realized pricing for the Company's crude oil, natural gas
liquids and bitumen in the third quarter was $93.23 per barrel,
compared to $70.14 per barrel in the third quarter of 2012. U.S.
realized refining margins declined to an average U.S. $11.86 per
barrel compared to U.S. $24.36 per barrel in the third quarter of
2012.  
KEY AREA SUMMARY AND GROWTH UPDATE 
THE FOUNDATION BUSINESS 


 
--  Heavy Oil

 
Consistent performance from the Company's Heavy Oil business resulted
in production of approximately 123,000 bbls/day, compared to
approximately 115,000 bbls/day in the third quarter of 2012. Total
production from thermal developments, including Tucker, was
approximately 48,000 bbls/day compared to approximately 37,800
bbls/day a year ago. 
The 3,500 bbls/day Sandall thermal development is now approximately
95 percent complete, with first production planned in the first half
of 2014. 
Design and construction continued at the 10,000 bbls/day commercial
thermal project at Rush Lake, with commissioning scheduled in
mid-2015. Results from the two-well pair pilot are continuing to meet
expectations. 
Forty-five horizontal heavy oil wells were drilled in the third
quarter, with 91 wells drilled to date out of a planned 140-well
program for 2013. Ninety-three wells were drilled using Cold Heavy
Oil Production with Sand (CHOPS), with 152 drilled to date as part of
a planned 200-well program this year. 


 
--  Western Canada

 
Gas Resource Plays 
Drilling continued with a four-rig program at the Ansell liquids-rich
gas play. Twenty wells have been completed at Ansell to date in 2013. 
Well completion activities are underway at the first four-well pad at
Kaybob in the Duvernay play, with first production expected in the
early 2014 timeframe. Drilling began on two additional wells on a
second well pad. 
Oil Resource Plays 
Thirty-seven wells were drilled on the Bakken, Viking, Cardium and
Lower Shaunavon oil resource plays, bringing the total number of
wells drilled across the portfolio to 85 (gross) for 2013. Nineteen
oil resource wells were completed over the third quarter. 
Construction of an all-season access road is being finalized at the
Slater River Canol play in the Northwest Territories. A proposed
summer 2014 program for two vertical wells is awaiting final approval
from regulatory authorities. 
GROWTH PILLARS 


 
--  Asia Pacific Region

 
The Liwan Gas Project is nearing completion with first production
planned in the coming months. Commissioning of the onshore gas plant
and shallow water central platform is underway and construction is
continuing on the deepwater facilities to connect the nine wells and
the pipeline to the platform.  
Work is advancing on the Liuhua 34-2 field, which is scheduled to be
tied into the main Liwan 3-1 deepwater facilities in the second half
of 2014.  
Natural gas from the fields will be processed at an onshore gas plant
and sold to the mainland China market. Fixed-price sales agreements
are in place for all of the planned production from both fields,
while negotiations for the Liuhua 29-1 field gas continue.  
Offshore Taiwan, work has commenced on a two-dimensional seismic
survey on a deepwater exploration block located off the island's
southwest coast. 


 
--  Oil Sands

 
The 60,000 bbls/day (30,000 bbls/day net) first phase of the Sunrise
Energy Project is approximately 80 percent complete as it advances
towards initial production in late 2014. 
Work continued on the Central Processing Facility (CPF) with all
module fabrication completed and major equipment installed.
Commissioning is underway for the first two of eight well pads, with
the rest targeted for completion by the end of the year. Construction
of the operations control centre is progressing as planned. 


 
--  Atlantic Region

 
Husky and its partner announced a significant discovery of light,
high-quality oil at the Bay du Nord prospect approximately 500
kilometres northeast of St. John's, Newfoundland and Labrador. 
The well is the third discovery in the deepwater Flemish Pass Basin
and further advances the Company's exploration and development
program in the Atlantic Region. Best estimate contingent resources
are estimated by Husky at 400 million barrels (on a 100 percent
working interest basis) as of September 23, 2013. Additional
prospective resources have been identified and further evaluation is
planned. Husky has a 35 percent working interest in the Bay du Nord,
Harpoon and Mizzen discoveries. Statoil is the operator. 
The Company continued to develop its White Rose satellite fields. Gas
injection at the South White Rose extension, which is expected to
enhance production, is scheduled to begin in the fourth quarter of
2013. The Company's proved plus probable plus possible reserves are
20 million barrels of oil (16.8 million barrels probable and 3.1
million barrels possible, Husky W.I. share, as of December 31, 2012).
Production from South White Rose will be tied back to the SeaRose
FPSO vessel, with first oil anticipated by the end of 2014. 
A benefits agreement has been signed with the Government of
Newfoundland and Labrador for the West White Rose development.
Detailed engineering is underway to build a fixed wellhead platform,
with first oil planned in the 2017 timeframe. 
Drilling has commenced on the Company's fifth production well at the
North Amethyst subsea tieback, while a fourth water injection well
was completed and brought online in the third quarter. 
Hydrocarbons were discovered at a Husky-operated step-out well at
Northwest White Rose and results continue to be evaluated.  
DOWNSTREAM 
Preliminary design work has started on a proposed upgrading project
at the Lima, Ohio Refinery to process up to 40,000 bbls/day of
Western Canadian heavy oil, while maintaining the capability to
refine lighter crudes.  
By increasing the flexibility of its crude feedstock options, product
range and the markets it is able to access, the Company is improving
its ability to respond more quickly and efficiently to the market. 
At the partner-operated refinery in Toledo, Ohio, work continued on a
Hydrotreater Recycle Gas Processor to improve operational integrity
and plant performance. The project is scheduled for completion in
2014.  
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 September 30, 2013. The dividend will be payable on January 2,
2014 to shareholders of record at the close of business on November
28, 2013. 
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 October 1, 2013 to December 31,
2013. The dividend of $0.27813 per Series 1 Preferred Share will be
payable on December 31, 2013 to holders of record at the close of
business on November 28, 2013. 
CONFERENCE CALL  
A conference call will be held on Thursday, October 24 at 10 a.m.
Mountain Time (12 p.m. Eastern Time) to discuss Husky's third 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 Senior
Downstream VP Bob Baird will participate in the call. To listen to a
recording of the call, available at 12 p.m. Mountain Time on October
24, 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 November 24, 2013

 
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 new 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;
    the anticipated duration of production constraints created by third-
    party infrastructure outages and downtime in Western Canada; and
    expected effect of reduced dry gas production and redirected capital on
    the Company's gas production as compared with the Company's previously
    issued guidance range for gas; 
--  with respect to the Company's Asia Pacific region: planned timing of
    first production at the Company's Liwan Gas Project; processing and
    sales plans for natural gas produced from the Company's Liwan Gas
    Project; and scheduled timing of tie-in at the Company's Liuhua 34-2
    field; 
--  with respect to the Company's Atlantic region: scheduled timing of
    commencement, and anticipated benefits, of gas injection at the
    Company's South White Rose extension project; anticipated timing of
    first oil production from the Company's South White Rose extension
    project, along with tie-back plans for such production; expected
    duration of a planned maintenance offstation at the Terra Nova FPSO; and
    planned timing of first production at the Company's West White Rose
    development;  
--  with respect to the Company's Oil Sands properties: scheduled timing of
    first production at the Company's Sunrise Energy Project; and scheduled
    timing of completion of construction of field facilities at the
    Company's Sunrise Energy Project; 
--  with respect to the Company's Heavy Oil properties: scheduled timing of
    first production, and anticipated volumes of production, at the
    Company's Sandall heavy oil thermal development project; expected timing
    of commissioning and volumes of production for the Company's Rush Lake
    thermal development project; and the Company's horizontal and CHOPS
    drilling programs for 2013; 
--  with respect to the Company's Western Canadian oil and gas resource
    plays: the Company's 2014 drilling program at its Canol Shale project in
    the Northwest Territories; and anticipated timing of production from the
    Company's Kaybob project in the Duvernay play; and 
--  with respect to the Company's Downstream operating segment: plans to
    increase the processing capability of the Lima, Ohio refinery and the
    expected benefits of this increase; scheduled timing of completion of a
    Hydrotreater Recycle Gas Compressor Project at the BP-Husky Toledo, Ohio
    refinery; and anticipated benefits of a feedstock flexibility project at
    the BP-Husky Toledo, Ohio 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. 
Disclosure of Oil and Gas Information 
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. 
The Company has disclosed possible reserves. Possible reserves are
those additional reserves that are less certain to be recovered than
probable reserves. It is unlikely that the actual remaining
quantities recovered will exceed the sum of proved plus probable plus
possible reserves. There is a 10 percent probability that the
quantities actually recovered will equal or exceed the sum of proved
plus probable plus possible reserves. 
The estimates of reserves for individual properties may not reflect
the same confidence level as estimates of reserves for all
properties, due to the effects of aggregation. The Company has
disclosed its total reserves in Canada in its Annual Information Form
for the year ended December 31, 2012, which reserves disclosure is
incorporated by reference herein.  
The Company has disclosed best-estimate contingent resources in this
news release. 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. 
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 Atlantic Region discoveries as reserves
include additional 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.  
The Company has disclosed prospective resources in this news release.
Prospective resources are those quantities of petroleum estimated, as
of a given date, to be potentially recoverable from undiscovered
accumulations by application of future development projects.
Prospective resources have both an associated chance of discovery and
a chance of development. Prospective resources are further subdivided
in accordance with the level of certainty associated with recoverable
estimates assuming their discovery and development and may be
subclassified based on project maturity. There is no certainty that
any portion of the resources will be discovered. If discovered, there
is no certainty that it will be commercially viable to produce any
portion of the resources." 
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" and "prospective 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:
Rob McInnis
Manager, Investor Relations
Husky Energy Inc.
403-298-6817 
Media Inquiries:
Mel Duvall
Manager, Media & Issues
Husky Energy Inc.
403-513-7602
 
 
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