CALGARY, AB--(Marketwired - February 26, 2016) - Husky Energy (TSX: HSE) continues to take decisive action to fortify its business for the long term.

"Our continuing structural transformation over the past five years into a lower sustaining capital business is setting the foundation for the Company to continue to improve its resilience through this extended period of commodity price turmoil," said CEO Asim Ghosh.

"Our business plan will balance capital expenditures with cash flow at a $30 US WTI price planning assumption. 2016 will see us further reduce our earnings break-even point."

With a 2016 capital plan in the range of $2.1-2.3 billion, the Company is set to continue its transformation into a low sustaining capital business. By the end of the year, more than 40 percent of the overall production base is expected to come from these types of projects, compared to just eight percent in 2010. Low sustaining capital projects slated for completion in the near term include:

Project                                   Nameplate Capacity (net bbls/day) Status
Tucker Thermal Project (Colony) 5,000 Second quarter start
Edam East heavy oil thermal 10,000 Second quarter start
Edam West heavy oil thermal 4,500 Third quarter start
Vawn heavy oil thermal 10,000 Third quarter start
Sunrise Energy Project 30,000 Ramping up/Late 2016
BD gas field offshore Indonesia 9,000 boe/day 2017 start
  (2,400 boe/day liquids, 40 mmcf/day gas)  


Financial Highlights

  • Achieved more than $600 million in overall supply and procurement savings ($2.0 billion since 2010)
  • Cut capital expenditures 40 percent to $3.0 billion
  • Lowered sustaining and maintenance costs by 15-20 percent below historical averages
  • Reduced SG&A by about 26 percent
  • Decreased Lloyd thermal unit operating costs by 25 percent over the year
  • Lowered Tucker thermal unit operating costs by more than 55 percent over the year
  • Reduced Atlantic Region daily rig rate by about 50 percent
  • Recorded $490 million in Upgrading and U.S. Refining earnings
  • Delivered strong Canadian Refined Products earnings, including record earnings of $149 million at the Lloydminster asphalt refinery
  • Initiated process for the partial sale of select midstream assets in the Lloydminster region
  • Began assessment of a sale of royalty interests in Western Canada
  • Activated disposition of select legacy oil and natural gas assets in Western Canada

Operational Highlights

  • Increased annual production to 346,000 barrels of oil equivalent per day (boe/day), within guidance
  • Reserves replacement outpaced production, with an average proved reserves replacement ratio of 166 percent (excluding economic factors)

Heavy Oil

  • Successfully started up the 10,000 barrels per day (bbls/day) Rush Lake heavy oil thermal project, which averaged production of about 14,000 bbls/day in December
  • Installed a new sustaining well pad at the Tucker Thermal Project


  • Expanded the Saskatchewan Gathering System to support growing Lloyd thermal production
  • Signed agreement to expand the truck transport network, subject to final regulatory approvals
  • Advanced plans for the crude oil flexibility project at Lima Refinery

Asia Pacific Region

  • Continued strong production from the Liwan Gas Project
  • Installed the topsides and jacket at the liquids-rich BD field offshore Indonesia, with steady progress on construction of the FPSO (floating production, storage and offloading) vessel and commencement of development drilling
  • Advanced three additional shallow water gas fields offshore Indonesia (MDA-MBH, MDK)
  • Signed a Production Sharing Contract (PSC) for the 15/33 exploration block offshore China

Oil Sands

  • First oil and steady ramp up of the long life Sunrise Energy Project

Atlantic Region

  • Commenced first production from two South White Rose extension wells
  • Achieved 97 percent uptime for the SeaRose FPSO

Reserves Growth Continued to Outpace Production

The average proved reserves replacement ratio for 2015 was 166 percent, excluding economic factors (136 percent including economic factors). This reflected new additions from heavy oil thermal projects, the Sunrise Energy Project, the Liwan Gas Project and the Company's natural gas fields offshore Indonesia.

Total proved reserves before royalties at the end of 2015 were 1.3 billion boe, and probable reserves were 1.6 billion boe.

Reserves growth followed a seven year trend of outpacing production. The average seven year proved reserves replacement ratio was 152 percent, excluding economic factors (146 percent including economic factors).


Average Upstream production in the fourth quarter was 357,000 boe/day. This included continued strong performance from Lloyd thermal projects, the ongoing ramp up of the Sunrise Energy Project and two new wells at the South White Rose extension in the Atlantic Region.

Fourth quarter throughputs at the refineries and Lloydminster Upgrader averaged 332,000 bbls/day, which takes into account reduced volumes at the Lima Refinery.

WTI prices averaged $42.18 US per barrel in the fourth quarter of 2015 compared to $73.15 US per barrel in 2014. Average realized pricing for total Upstream production in the fourth quarter was $34.89 per boe, compared to $55.53 in the fourth quarter of 2014.

U.S. refining Chicago market crack spreads averaged $14.00 US per barrel in the fourth quarter of 2015, which was comparable to the same period in 2014. The realized U.S. refining margin averaged $4.51 US per barrel in the fourth quarter, compared to a loss of $6.62 US in the fourth quarter of 2014.

The Company realized cash flow from operations of $640 million. This reflected the lower oil price environment, a wider heavy oil differential and a $72 million FIFO loss in U.S. Refining.

Earnings for the quarter were a net loss of $69 million and included the factors above, as well as:

  • A $14 million (after tax) write-down of inventory to net realizable value, primarily in U.S. Refining and Marketing
  • $50 million (after tax) in insurance recoveries for the Lima Refinery isocracker
  Three Months Ended Twelve Months Ended
  Dec. 31 2015 Sept. 30 2015 Dec. 31 2014 Dec. 31 2015 Dec. 31 2014
1) Daily Production, before royalties          
  Total Equivalent Production (mboe/day) 357 333 360 346 340
  Crude Oil and NGLs (mbbls/day) 247 223 243 231 237
  Natural Gas (mmcf/day) 661 658 702 689 621
2) Operating Netback ($/boe) (1)(2) 17.28 20.72 34.84 22.00 42.63
3) Refinery and Upgrader Throughput (mbbls/day) 332 291 344 308 318
4) Cash Flow from Operations(2) (Cdn $ millions) 640 674 1,145 3,329 5,535
  Per Common Share - Basic ($/share)  0.65 0.68 1.16 3.38 5.63
  Per Common Share - Diluted ($/share)   0.65  0.68  1.16  3.38  5.62
5) Net Earnings (loss) (Cdn $ millions)  (69) (4,092)(3) (603) (3,850) 1,258
  Per Common Share - Basic ($/share)    (0.08)  (4.17)  (0.62) (3.95)   1.26
  Per Common Share - Diluted ($/share)   (0.09) (4.19)   (0.65) (4.01)   1.20
6) Adjusted Net Earnings (loss)(2) (49) (101) 148 165 2,019
7) Capital Investment, including acquisitions  (Cdn $ millions)(5) 641 817 1,419 3,005 5,023
8) Dividend Per Common Share ($/share) 0.00(6) 0.30(4) 0.30 0.90(4) 1.20
(1) Operating netback includes results from Upstream Exploration and Production and excludes Upstream Infrastructure and Marketing. 
(2) Operating netback, cash flow from operations and adjusted net earnings (loss) are non-GAAP measures. Refer to the 2015 Annual MD&A, Section 11, which is incorporated herein by reference. 
(3) Q3 net earnings include $4 billion (after tax) in non-cash items. 
(4) Dividends declared for the third quarter of 2015 were issued in the form of common shares. 
(5) Capital Investment was revised during the fourth quarter of 2015 to exclude capital expenditures incurred by the Husky-CNOOC Madura Ltd. joint venture, which are classified as other investing activities on the Company's Consolidated Statements of Cash Flows.
(6) The quarterly common share dividend was suspended for the fourth quarter of 2015. 

Fourth Quarter Key Area Summary

Heavy Oil

Lloyd thermal production averaged approximately 56,800 bbls/day. This reflected steady production from seven thermal developments, including new volumes from the 10,000 bbls/day Rush Lake thermal project.

The 10,000 bbls/day Rush Lake 2 thermal project was sanctioned, with first oil expected in the 2018-2019 timeframe.

At the Tucker Thermal Project, a new sustaining well pad increased production to 15,000 bbls/day in the second half of 2015, compared to average production of about 10,800 bbls/day in 2014.

Operating costs in the fourth quarter, including energy, were about $7 per barrel for Lloydminster-area thermal production and about $10 per barrel at the Tucker Thermal Project.

The Company has commenced steaming at the Colony formation at Tucker. The reservoir has similar characteristics to the heavy oil reservoirs in the Lloydminster region and is suitable for development using thermal technology. First production from Colony is expected in the second quarter, with total Tucker production expected to progressively increase towards approximately 20,000 bbls/day in the second half of 2016.

Western Canada

Overall resource play production in Western Canada averaged approximately 39,600 boe/day in the fourth quarter, compared to about 36,200 boe/day in 2014.

The transition of the Western Canada portfolio is being advanced through a planned disposition of select legacy assets. Financial advisors have been engaged and a data room is open.

The Company realized about $100 million from the sale of assets in the fourth quarter.


Two integrated Downstream value chains supported production from Sunrise and the growing number of Lloyd thermal developments.

Construction work neared completion on the Saskatchewan Gathering System to accommodate growing Lloyd thermal production. Production from the Rush Lake thermal project began flowing in the newly expanded trunk pipeline, and a condensate pipeline is being completed.

An expansion of the Hardisty terminal was completed, which included increased pipeline connectivity, blending capacity and storage to support Upstream production.

The Company continued to advance the partial sale of select midstream assets in the Lloyd region, which includes pipeline and storage facilities. Husky intends to retain operatorship of these assets in order to maintain tight integration between Upstream production and Downstream facilities.

Asia Pacific Region


The Liwan Gas Project maintained steady production with combined gross gas sales volumes averaging about 294 million cubic feet per day (mmcf/day) in the fourth quarter. Gross sales of associated natural gas liquids were approximately 14,800 boe/day.

Husky signed a PSC for the 15/33 exploration block offshore China. Two wells are expected to be drilled in the 2017 timeframe.


Construction of a leased FPSO is almost half complete. The FPSO will process gas and liquids production from the liquids-rich BD field in the Madura Strait following anticipated first production in 2017. The topsides and jacket, which will be tied back to the FPSO, were installed and drilling of the four development wells has commenced. The wellhead platform and pipeline infrastructure construction is about two-thirds complete. Fixed price gas sales agreements are in place.

The Company and its partners further advanced development of the MDA-MBH and MDK natural gas fields towards first gas planned in the 2018-2019 timeframe. Once fully ramped up, combined net sales volumes from the BD, MDA-MBH and MDK fields are expected to be about 100 mmcf/day of gas and 2,400 boe/day of associated liquids.

Oil Sands

Production at the Sunrise Energy Project is increasing as expected, with recent peak gross volumes of more than 25,000 bbls/day compared to 13,000-14,000 bbls/day reported in late October.

The plan provides for a steady and deliberate ramp up towards 60,000 bbls/day (gross) around the end of 2016.

The reservoir continues to demonstrate performance in line with expectations:

  • The steam-oil ratio continues to steadily improve towards the design SOR of 3.0, while the oil cut is in line with the forecast range of 20-23 percent and continuing to improve as per plan. Both factors are consistent with the characteristics of a top-tier reservoir, and are indicators the plant is on track to achieve its full design capacity
  • The presence of strong producers on each well pad demonstrate good reservoir continuity

Steaming of all nine well pads was staggered over the course of last year. Steam chambers are continuing to build, with all 55 well pairs now producing bitumen.

The production plan for 2016 takes into consideration several operational activities that will contribute to the ongoing steady ramp up. These include:

  • During the first quarter, the oil treatment equipment at Plant 1B will be brought on line to provide additional bitumen processing capacity
  • A planned 10 day maintenance program will be performed on Plant 1A in the first half of 2016
  • Thirty-two Electric Submersible Pumps (ESPs) are now in operation in Sunrise production wells. ESPs contribute to overall production reliability. In 2016, the plan calls for up to 10 additional ESP well conversions

Atlantic Region

Average net production was about 43,500 bbls/day.

Two production wells at the South White Rose extension contributed about 15,000 bbls/day in net combined production in the fourth quarter.

In the Flemish Pass Basin, an ongoing exploration and appraisal program continued at the Bay du Nord discovery area.

A two-year contract was signed to secure the harsh-environment Henry Goodrich drilling rig for ongoing development drilling and near-field exploration. The rig is expected to commence work in mid-2016.



  • Maintenance work at Plant 1A at the Sunrise Energy Project is planned for the first half of 2016
  • The Ram River plant in Western Canada is scheduled to undergo a three-week turnaround, with an anticipated impact of about 2,200 boe/day averaged over the second quarter
  • A 28-day turnaround is planned in the second quarter at the partner-operated Terra Nova FPSO, with an anticipated net impact of about 1,300 boe/day averaged over the quarter
  • A 14-day turnaround is scheduled at the Liwan Gas Project in mid-year for the installation and tie-in of a second deepwater pipeline, with expected net impacts of approximately 4,600 boe/day averaged over the second quarter


  • A planned eight-week maintenance turnaround is scheduled at the Lima Refinery starting in the first quarter of 2016
  • An 11-week turnaround has been scheduled at the Toledo Refinery starting in the second quarter. During this time, the refinery will operate at 25 percent
  • The Prince George Refinery has scheduled a five-week turnaround in the second quarter


As previously announced, Husky has instituted a hedging program to support the delivery of its business plan. Currently, the hedges are for approximately 20 million barrels of oil production and use a put/call structure. The objective of the program is to preserve the strength of the Company's balance sheet and provide a measure of revenue certainty.

As previously announced, the Board of Directors did not declare a dividend on Husky's common shares for the fourth quarter of 2015. They will continue to review the dividend on a quarterly basis.

Regular dividend payments on each of the Cumulative Redeemable Preferred Shares, Series 1, Series 3, Series 5 and Series 7 will be paid for the three month period ended March 31, 2016. The dividends will be payable on March 31, 2016 to holders of record at the close of business on March 15, 2016.

Share Series Dividend Type Rate (%) Dividend Paid ($/share)
Series 1 Regular 4.45 $0.27813
Series 3 Regular 4.50 $0.28125
Series 5 Regular 4.50 $0.28125
Series 7 Regular 4.60 $0.28750

Husky has filed its Annual Information Form (AIF), audited consolidated financial statements and related Management's Discussion and Analysis for the year ended December 31, 2015 with Canadian securities regulators on the System for Electronic Document Analysis and Retrieval (SEDAR).

The AIF includes the disclosure and reports relating to oil and gas reserves data and other disclosures for oil and gas activities required pursuant to National Instrument 51-101 of the Canadian Securities Administrators.

In addition, Husky filed its Annual Report on Form 40-F for the year ended December 31, 2015 on the Electronic Data Gathering, Analysis, and Retrieval (EDGAR) system in the United States. The report includes the AIF, audited consolidated financial statements and related Management's Discussion and Analysis.

Copies of the AIF, audited consolidated financial statements and related Management's Discussion and Analysis may be accessed electronically from Copies of the Annual Report on Form 40-F may be accessed electronically from Both the Canadian and U.S. disclosure documents may also be accessed electronically from Husky's website at


A conference call will take place on Friday, February 26 at 9 a.m. Mountain Time (11 a.m. Eastern Time) to discuss Husky's year-end and fourth quarter results. CEO Asim Ghosh, COO Rob Peabody, CFO Jon McKenzie and Downstream Senior VP Bob Baird will participate in the call.

To listen live:
To listen to a recording (after 10 a.m. Feb. 26)          
Canada and U.S. Toll Free: 1-800-319-4610  Canada and U.S. Toll Free: 1-800-319-6413 
Outside Canada and U.S.: 1-604-638-5340  Outside Canada and U.S.: 1-604-638-9010 
  Passcode: 2658 followed by # sign 
  Duration: Available until March 27, 2016 
  Audio webcast: Available for 90 days at 
under Investor Relations 

Husky Energy is one of Canada's largest integrated energy companies. It is headquartered in Calgary, Alberta, Canada and its shares are publicly traded on the Toronto Stock Exchange under the symbols HSE, HSE.PR.A, HSE.PR.C, HSE.PR.E and HSE.PR.G. More information is available at


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. 

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 Company's 2016 capital plan; and anticipated  percentage of production base from low sustaining capital projects by the  end of 2016;
  • with respect to the Company's Asia Pacific  Region: development plans at the BD gas field in the Madura Strait  offshore Indonesia; scheduled startup of and expected net sales volumes  from the BD field; drilling plans at the 15/33 exploration block offshore  China; planned timing of first gas from the MDA-MBH and MDK gas fields in  the Madura Strait; anticipated combined net peak sales volumes from the  BD, MDA-MBH, and MDK fields; and scheduled timing, duration, and impact of  a turnaround and associated installation and tie-in of a second deepwater  pipeline at the Liwan Gas Project;
  • with respect to the  Company's Atlantic Region: expected timing of commencement of work by the  Henry Goodrich drilling rig; and scheduled timing, duration, and impact of  a turnaround at the Terra Nova FPSO;
  • with respect to the Company's Oil Sands  properties: planned timing of ramp up to peak production at the Sunrise  Energy Project; 2016 production plan at the Sunrise Energy Project; and  planned timing of maintenance work at Plant 1A at the Sunrise Energy  Project; 
  • with respect to the Company's Heavy Oil  properties: scheduled startup of and net peak daily production from the  Company's Tucker (Colony), Edam East, Edam West, Vawn, and Rush Lake 2  heavy oil thermal projects; and anticipated timing and volume of increase  in production from the Tucker project;
  • with respect to the Company's Western Canadian  oil and gas resource plays: planned sales of royalty interests in Western  Canada, and select legacy oil and natural gas assets in Western Canada;  and scheduled timing, duration, and impact of a turnaround at the Ram  River plant; and
  • with respect to the Company's Downstream  operating segment: planned sale of select midstream assets in the  Lloydminster region; and scheduled timing and duration of turnarounds at  the Lima, Toledo, and Prince George Refineries.

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, 2015 and other documents filed with securities regulatory authorities (accessible through the SEDAR website and the EDGAR website describe 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. None of these measurements are used to enhance the Company's reported financial performance or position. With the exception of net operating earnings and cash flow from operations, there are no comparable measures to these non-GAAP measures in accordance with IFRS. These non-GAAP measures are considered to be useful as complementary measures in assessing Husky's financial performance, efficiency and liquidity. These terms include:

  • Adjusted Net Earnings is a non-GAAP measure comprised of net earnings excluding extraordinary and non-recurring items such as after-tax property, plant and equipment impairment charges and after-tax inventory write-downs not considered to be indicative of the Company's on-going financial performance. Adjusted net earnings is a complementary measure used in assessing Husky's financial performance through providing comparability between periods. Refer to the 2015 Annual MD&A, Section 11, which is incorporated herein by reference.
  • 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. Husky's determination of cash flow from operations may not be comparable to that reported by other companies. Cash flow from operations equals net earnings plus items not affecting cash which include accretion, depletion, depreciation, amortization and impairment, inventory write-downs to net realizable value, exploration and evaluation expense, deferred income taxes, foreign exchange, stock-based compensation, gain or loss on sale of assets and other non‐cash items. Refer to the 2015 Annual MD&A, Section 11, which is incorporated herein by reference.
  • Operating netback is a common non-GAAP metric used in the oil and gas industry. This measurement assists management and investors to evaluate the specific operating performance by product at the oil and gas lease level. The operating netback was determined as realized price less royalties, operating costs and transportation on a per unit basis. Refer to the 2015 Annual MD&A, Section 11, which is incorporated herein by reference.

Disclosure of Oil and Gas Information

Unless otherwise stated, reserve and resource estimates in this news release, have been prepared by internal qualified reserves evaluators in accordance with the Canadian Oil and Gas Evaluation Handbook, have an effective date of December 31, 2015 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 consistent with other oil and gas companies' disclosures, and is calculated on an energy equivalence basis applicable at the burner tip whereby one barrel of crude oil is equivalent to six thousand cubic feet of natural gas. The term boe is used to express the sum of the total company products in one unit that can be used for comparisons. Readers are cautioned that the term boe may be misleading, particularly if used in isolation. This measure is used for consistency with other oil and gas companies and does not represent value equivalency at the wellhead.

The Company uses the term reserve replacement ratio, which is consistent with other oil and gas companies' disclosures. 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. The reserve replacement ratio measures the amount of reserves added to a company's reserve base during a given period relative to the amount of oil and gas produced during that same period. A company's reserve replacement ratio must be at least 100% for the company to maintain its reserves. The reserve replacement ratio only measures the amount of reserves added to a company's reserve base during a given period.

Note to U.S. Readers
All currency is expressed in Canadian dollars unless otherwise directed.

Contact Information:

For further information, please contact:

Investor Inquiries:
Dan Cuthbertson
Manager, Investor Relations
Husky Energy Inc.

Media Inquiries: 
Mel Duvall
Manager, Media & Issues
Husky Energy Inc.