CALGARY, AB–(Marketwired – February 24, 2017) – Husky Energy Inc. (TSX: HSE)
Increased production of 327,000 barrels of oil equivalent per day (boe/day) and steady refining throughputs contributed to funds from operations of $670 million and free cash flow of $279 million in the fourth quarter.
“This past year has been challenging for the sector, but by responding quickly to the new pricing environment Husky is well positioned for the next phase of growth,” said CEO Rob Peabody. “We have a strong balance sheet and are advancing a deep portfolio of projects.
“From this firm foundation, we will continue to expand margins, further reduce our break-even oil price and increase our ability to generate free cash flow.”
Fourth quarter highlights included:
- Net thermal production was 120,000 barrels per day (bbls/day) at the end of December, 2016. This included Lloyd thermal projects, the Tucker Thermal Project and the Sunrise Energy Project. Net production from these projects over the fourth quarter averaged 115,300 bbls/day, an increase of 46 percent over the same period in 2015.
- The Edam East, Vawn and Edam West Lloyd thermal projects averaged 28,500 bbls/day, surpassing their combined design capacity by 15 percent with an average steam-oil ratio of 2.2.
- U.S. refining capacity utilization was 92 percent compared to 84 percent in the third quarter, and 81 percent in the fourth quarter of 2015, reflecting work completed in 2016 to improve efficiencies.
- Capital expenditures in the fourth quarter were $391 million. Including equity accounted entities, total annual capital spending was $1.9 billion. This was approximately $200 million less than the lower end of the 2016 guidance range, reflecting the ongoing cost reduction program and improved productivity. In addition to the savings achieved, an expanded work program was completed.
- Free cash flow was $279 million in the fourth quarter, contributing to annual free cash flow of $371 million.
2016 FOURTH QUARTER RESULTS
Upstream production was 327,000 boe/day, compared to 357,000 boe/day in the fourth quarter of 2015. This reflected the asset dispositions in Western Canada, natural declines and planned turnarounds, partially offset by growing thermal production and increased volumes from the Liwan Gas Project.
Upgrading and refining throughputs averaged 351,000 bbls/day, up from 338,000 bbls/day in the fourth quarter of 2015.
WTI prices averaged $49.29 US per barrel compared to $42.18 US per barrel in the fourth quarter of 2015.
Average realized pricing for total Upstream production increased to $39.90 per boe from $34.89 per boe in the fourth quarter of 2015. This included average realized gas pricing of $13.10 Cdn per thousand cubic feet (mcf) for sales gas at Liwan.
The Chicago 3:2:1 crack spread averaged $10.59 US per barrel, compared to $13.73 US per barrel in the fourth quarter of 2015. Average realized U.S. refining margins were $9.86 US per barrel, up from $4.51 US per barrel a year ago.
Overall Upstream operating costs were reduced to $13.92 per barrel from $14.51 per barrel in the fourth quarter of 2015.
This was in part due to the growing contribution from lower cost Lloyd thermal production and the Tucker Thermal Project, which together represented more than 30 percent of overall production in the fourth quarter at 98,400 bbls/day.
Upstream operating netbacks were $22.30, up from $15.70 in the third quarter of 2016 and $16.19 in the fourth quarter of 2015.
Funds from operations (previously described as cash flow from operations) was $670 million, compared to $640 million in the fourth quarter of 2015, and included a pre-tax FIFO gain of $39 million. This did not take into account $23 million in cash received as pre-payment for future gas volumes at Liwan.
Capital expenditures in the fourth quarter were $391 million, leading to free cash flow of $279 million.
Net earnings were approximately $186 million, compared to a loss of $69 million in the fourth quarter of 2015, and included one-time items associated with the Western Canada asset sales and a net impairment reversal of $202 million. Excluding one-time items, adjusted net earnings were a loss of $6 million.
| Three Months Ended | Twelve Months Ended | ||||||||||
| Dec. 31 2016 | Sept. 30 2016 | Dec. 31 2015 | Dec. 31 2016 | Dec. 31 2015 | |||||||
| 1) Daily Production, before royalties | |||||||||||
| Total Equivalent Production (mboe/day) | 327 | 301 | 357 | 321 | 346 | ||||||
| Crude Oil and NGLs (mbbls/day) | 235 | 214 | 247 | 229 | 231 | ||||||
| Natural Gas (mmcf/day) | 555 | 521 | 661 | 556 | 689 | ||||||
| 2) Operating Netback ($/boe) (1)(2) | 22.32 | 15.70 | 17.28 | 16.19 | 22.00 | ||||||
| 3) Refinery and Upgrader Throughput (mbbls/day) | 351 | 320 | 338 | 310 | 313 | ||||||
| 4) Funds from Operations(2) ($ millions) | 670 | 484 | 640 | 2,076 | 3,329 | ||||||
| Per Common Share – Basic ($/share) | 0.67 | 0.48 | 0.65 | 2.07 | 3.38 | ||||||
| Per Common Share – Diluted ($/share) | 0.67 | 0.48 | 0.65 | 2.07 | 3.38 | ||||||
| 5) Net Earnings ($ millions) | 186 | 1,390 | (69) | 922 | (3,850) | ||||||
| Per Common Share – Basic ($/share) | 0.19 | 1.37 | (0.08) | 0.88 | (3.95) | ||||||
| Per Common Share – Diluted ($/share) | 0.19 | 1.37 | (0.09) | 0.88 | (4.01) | ||||||
| 6) Adjusted Net Earnings (loss)(2) ($ millions) | (6) | (100) | (53) | (655) | 149 | ||||||
| 7) Capital Investment, including acquisitions ($ millions) | 391 | 309 | 641 | 1,705 | 3,005 | ||||||
| 8) Net Debt(2) ($ billion) | 4.0 | 4.1 | 6.7 | 4.0 | 6.7 | ||||||
| 9) Debt to Capital Employed(2) | – | – | – | 23.2 | 28.9 | ||||||
(1) Includes results from Upstream Exploration and Production and excludes Upstream Infrastructure and Marketing.
(2) Operating netback, funds from operations, adjusted net earnings (loss), net debt and debt to capital employed are non-GAAP measures. Refer to Section 11.3 of the 2016 Annual MD&A, which is incorporated herein by reference.
FOURTH QUARTER OPERATIONS SUMMARY
Thermal Production
Average net thermal production from Lloyd thermal projects, the Tucker Thermal Project and the Sunrise Energy Project was 115,300 bbls/day, an increase of 46 percent over the same period in 2015.
Production from a trio of Lloyd thermal projects at Edam East, Vawn and Edam West averaged 28,500 bbls/day. The projects, which began production in 2016, are currently producing more than 15 percent above their combined design capacity of 24,500 bbls/day with an average steam-oil ratio of 2.2.
Construction continued to advance on the 10,000 bbls/day Rush Lake 2 Lloyd thermal project, with production on track for the first half of 2019.
The Tucker Thermal Project averaged production of 20,800 bbls/day, a 38 percent increase over the fourth quarter of 2015. Steaming is now under way at a new eight-well pad, with first production expected in the second quarter of 2017. Drilling has also commenced at a 15-well pad, with first oil planned in the first half of 2018. Production from Tucker is anticipated to ramp up throughout 2017 and 2018 towards 30,000 bbls/day.
At the Sunrise Energy Project, gross production averaged 33,800 bbls/day. Current production is about 36,000 bbls/day, with production per well pair averaging about 650 bbls/day.
Western Canada Production
The Western Canada business is moving ahead with increased capital efficiency and a focus on fewer, more material resource plays. The repositioned portfolio is now more than 70 percent gas-weighted, providing a natural hedge for the Company’s energy requirements at its thermal projects and refineries.
A 16-well program is planned in 2017 targeting the Wilrich formation in the Ansell and Kakwa areas.
Downstream
At the Lima Refinery, throughput averaged 165,000 bbls/day compared to 144,800 bbls/day in the fourth quarter of 2015.
At the partner-operated Toledo refinery, the Company is realizing additional margins from its increased capacity to process high-TAN crude. Throughput averaged 78,800 bbls/day (net to Husky), compared to 73,000 bbls/day in the fourth quarter of 2015. Husky is now lifting and marketing its refined products from Toledo and first deliveries commenced in January 2017.
Asia Pacific
China
At the Liwan Gas Project, gross sales gas volumes averaged 305 million cubic feet per day (mmcf/day), with associated liquids production averaging 17,000 bbls/day. The Company realized pricing of $13.10 per mcf for its sales gas production. Current gross sales gas production at Liwan is about 290 mmcf/day.
Indonesia
Construction was finalized at the liquids-rich BD project in the Madura Strait. The shallow water platform and subsea pipeline installation is complete, and the floating production, storage and offloading (FPSO) vessel is on site. The project is expected to ramp up to its full sales gas rate during the second half of 2017, with a net daily sales target of 40 mmcf/day of gas and 2,400 bbls/day of liquids.
At the MDA-MBH fields, government approval was received for the award of the bid for a leased floating production unit. The engineering, procurement, construction and installation contract has been signed and the platforms are under construction. First gas is expected in the 2018-2019 timeframe, with an additional shallow water field at MDK to be tied in during the same period.
Total net sales gas volumes from BD, MDA-MBH and MDK are expected to be approximately 100 mmcf/day of gas and 2,400 bbls/day of associated liquids once production is fully ramped up.
Atlantic
Overall production averaged approximately 34,300 bbls/day, with high-netback extension projects continuing to mitigate natural declines.
A new infill well was completed at the South White Rose extension in the fourth quarter and is currently producing 3,000 bbls/day net to Husky and continuing to ramp up.
The first of two additional White Rose infill wells scheduled in 2017 is now on production and currently producing 8,600 bbls/day net to Husky. All of the wells are tied back to the SeaRose FPSO, providing for improved capital efficiencies.
The West White Rose extension will be considered for sanction this year. In the Flemish Pass Basin, preparations were finalized for two exploration wells that are scheduled to be drilled beginning in mid-2017.
2016 ANNUAL RESULTS
Financial
The Company reduced its net debt by 40 percent to about $4 billion and also has $4 billion in undrawn credit facilities and $1.3 billion of cash in hand.
Highlights included:
- Funds from operations was $2.1 billion, not including $209 million in cash received as pre-payment for future gas volumes at the Liwan Gas Project.
- Free cash flow was $371 million.
- Net earnings were $922 million. Adjusted net earnings were a loss of $655 million.
- The creation of a new Midstream partnership unlocked $1.7 billion in cash and secured takeaway capacity for at least eight new Lloyd thermal projects. Husky holds a 35 percent equity interest and maintains operatorship.
Operational
Average annual production was 321,000 boe/day. This takes into account the sale of approximately 32,000 boe/day of non-core production in Western Canada, including royalty volumes. Annual production did not include 43 mmcf/day of deferred volumes at Liwan, for which cash was received.
Thermal Production
- Average annual thermal production from Lloyd thermal projects, the Tucker Thermal Project and the Sunrise Energy Project was 97,400 bbls/day, a 55 percent increase compared to 2015.
- Construction was progressed on the 10,000 bbls/day Rush Lake 2 Lloyd thermal project, which is scheduled for startup in the first half of 2019.
- Three new Lloyd thermal developments with a combined design capacity of 30,000 bbls/day were sanctioned. Subject to regulatory approval, first oil from Dee Valley, Spruce Lake North and Spruce Lake Central is expected in 2020.
- Fourteen additional Lloyd thermal projects with a combined design capacity of 110,000 bbls/day were identified for potential development.
Western Canada Production
- Resource play production was 34,500 boe/day, primarily in the Wilrich and Cardium zones.
- A series of dispositions was completed, representing about 32,000 boe/day of non-core production.
Downstream
- Heavy crude feedstock processing capacity at the Lima Refinery was increased to 10,000 bbls/day following completion of the first phase of the crude oil flexibility project. The full scope of the project is expected to expand heavy crude processing capacity to 40,000 bbls/day by the end of 2018.
- High-TAN processing capacity at the Toledo Refinery was increased to 65,000 bbls/day.
- Engineering work commenced on a potential 30,000 bbls/day expansion of Lloyd asphalt capacity; the project will be considered for sanction this year.
Asia Pacific
- A second subsea pipeline was installed at the Liwan Gas Project to provide for additional operating flexibility.
- A wellhead platform and pipeline infrastructure were completed at the liquids-rich BD project offshore Indonesia.
Atlantic
- First oil was produced from the Hibernia formation well at North Amethyst in the Jeanne d’Arc Basin.
- High-netback satellite extensions and infill wells continued to extend the life of the main White Rose field.
2016 RESERVES REPLACEMENT
Total proved reserves before royalties at the end of 2016 were 1.2 billion boe, and probable reserves were 1.6 billion boe. The average five-year proved reserves replacement ratio, including acquisitions and dispositions, was 121 percent, excluding economic factors (109 percent including economic factors).
Taking into account the acquisitions and dispositions, which included a reduction of 86 million boe of proved reserves in Western Canada, the 2016 proved reserves replacement ratio was 19 percent, excluding economic factors. Including economic factors, the proved reserves replacement ratio was 15 percent.
Not including the acquisitions and dispositions, the 2016 proved reserves replacement ratio was 92 percent, excluding economic factors. Including economic factors, the proved reserves replacement ratio was 88 percent.
Proved reserves additions and revisions of 104 million boe reflect major additions from Lloyd thermal projects, the Tucker Thermal Project and the Liwan Gas Project.
NEAR AND MID-TERM PROJECT STATUS
| Thermal Developments | ||
| Tucker Thermal Project | Additional eight-well pad; first oil in Q2 2017 | |
| Tucker Thermal Project | Additional 15-well pad; first oil in first half of 2018 | |
| Sunrise Energy Project | 14 new well pairs; first oil in first half of 2018 | |
| 10,000 bbls/day Rush Lake 2 Lloyd Thermal Project | First oil in first half of 2019 | |
| 10,000 bbls/day Dee Valley Lloyd Thermal Project | First oil in 2020 | |
| 10,000 bbls/day Spruce Lake North Lloyd Thermal Project | First oil in 2020 | |
| 10,000 bbls/day Spruce Lake Central Lloyd Thermal Project | First oil in 2020 | |
| Western Canada Production | ||
| 16-well drilling program | Under way | |
| Downstream | ||
| Lima Refinery Crude Oil Flexibility Project | Completion in 2018 | |
| Lloydminster Asphalt Project | Sanction consideration in 2017 | |
| Asia Pacific | ||
| Liquids-rich BD Project offshore Indonesia | Startup in Q2 2017 | |
| MDA-MBH and MDK gas fields offshore Indonesia | Startup in 2018-2019 | |
| MAC gas field offshore Indonesia | Plan of development approved | |
| Liuhua 29-1 gas field offshore China | Contract negotiations in progress | |
| Atlantic | ||
| Two White Rose infill wells | First oil in Q1 and Q4 2017 | |
| West White Rose Extension | Sanction consideration in 2017 | |
2017 PLANNED MAINTENANCE AND TURNAROUNDS
Upstream
- A three-week turnaround is planned at the SeaRose FPSO in the third quarter.
- A three-week turnaround at the partner-operated Terra Nova FPSO is scheduled in the third quarter.
Downstream
- The Lloydminster Upgrader is scheduled to undergo a seven-week turnaround beginning in the second quarter.
- A four-week turnaround is planned at the Lloydminster asphalt refinery in the second quarter.
- A five-week partial turnaround is scheduled at the Lima Refinery in the fourth quarter.
CORPORATE DEVELOPMENTS
Regular dividend payments on each of the Cumulative Redeemable Preferred Shares – Series 1, Series 2, Series 3, Series 5 and Series 7 – will be paid for the three-month period ended March 31, 2017. The dividends will be payable on March 31, 2017 to holders of record at the close of business on March 14, 2017.
| Share Series | Dividend Type | Rate (%) | Dividend Paid ($/share) | |||
| Series 1 Series 2 |
Regular Regular |
2.404 2.239 |
$0.15025 $0.13802 |
|||
| 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, 2016 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, 2016 with the United States Securities and Exchange Commission 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 at www.sedar.com. Copies of the Annual Report on Form 40-F may be accessed at www.sec.gov. Both the Canadian and U.S. disclosure documents may also be accessed on Husky’s website at www.huskyenergy.com
CONFERENCE CALL
A conference call will take place on Friday, February 24 at 9 a.m. Mountain Time (11 a.m. Eastern Time) to discuss the Company’s fourth quarter and annual results. CEO Rob Peabody and CFO Jon McKenzie will participate in the call.
| To listen live: | To listen to a recording (after 10 a.m. MT on February 24) | |
|
Canada and U.S. Toll Free: 1-800-319-4610 |
Canada and U.S. Toll Free: 1-800-319-6413 |
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| Outside Canada and U.S.: 1-604-638-5340 | Outside Canada and U.S.: 1-604-638-9010 | |
| Passcode: 1119 | ||
| Duration: Available until March 24, 2017 | ||
| Audio webcast: Available for 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 its shares are publicly traded on the Toronto Stock Exchange under the symbols HSE, HSE.PR.A, HSE.PR.B, HSE.PR.C, HSE.PR.E and HSE.PR.G. 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.
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”, “forecast”, “guidance”, “could”, “may”, “would”, “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 business: anticipated volumes of peak combined net sales volumes of gas and NGL from the BD, MDA, MBH and MDK fields; anticipated timing of first production at the MDA, MBH, and MDK gas fields; and anticipated timing of startup and of achieving full sales gas rates at, and net daily sales targets for gas and liquids from, the BD field;
- with respect to the Company’s Atlantic business: anticipated timing of a second additional White Rose infill well; timing to consider sanction of the West White Rose extension project; anticipated timing of exploration drilling in the Flemish Pass Basin; and anticipated timing and duration of turnarounds at the SeaRose FPSO and Terra Nova FPSO;
- with respect to the Company’s Oil Sands properties: anticipated timing of first oil from new well pairs at the Company’s Sunrise Energy Project;
- with respect to the Company’s Heavy Oil properties: anticipated timing of first production from a new eight-well pad and a new 15-well pad, expected ramp up through 2017 and 2018, and plant capacity, at the Tucker Thermal Project; anticipated timing of first production from, and combined nameplate capacities of, the Dee Valley, Spruce Lake North and Spruce Lake Central thermal projects; expected timing for first production from, and nameplate capacity of, the Rush Lake 2 Lloyd thermal development; and anticipated combined nameplate capacities of identified potential Lloyd thermal developments;
- with respect to the Company’s Western Canadian oil and gas resource plays: the Company’s 2017 drilling plans for the Ansell and Kakwa areas; and
- with respect to the Company’s Downstream operating segment: anticipated timing of completion, outcome, and benefits of the crude oil flexibility project at the Company’s Lima Refinery; potential expansion of the Company’s asphalt processing capacity in Lloydminster and the anticipated timing to consider the sanctioning of the project; and anticipated timing and duration of turnarounds at the Lloydminster Upgrader, Lima Refinery and Lloydminster asphalt refinery.
In addition, statements relating to “reserves” are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of reserves 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 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, 2016 and other documents filed with securities regulatory authorities (accessible through the SEDAR website www.sedar.com and the EDGAR website www.sec.gov) 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 the terms free cash flow, operating netback, funds from operations, adjusted net earnings (loss), net debt and debt to capital employed, which are non-GAAP measures. Refer to Section 11.3 of the 2016 Annual MD&A, which is incorporated herein by reference.
Disclosure of Oil and Gas Information
Unless otherwise stated, reserve 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, 2016 and represent Husky’s share. Unless otherwise noted, projected and historical production numbers given represent Husky’s share. Unless otherwise noted, historical production numbers are for the year ended December 31, 2016.
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.
Steam-oil ratio measures the average volume of steam required to produce a barrel of oil. This measure does not have any standardized meaning and should not be used to make comparisons to similar measures presented by other issuers.
Note to U.S. Readers
The Company reports its reserves 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 information in accordance with Canadian disclosure requirements, it may use certain terms in that disclosure that U.S. oil and gas companies generally do not include or may be prohibited from including in their filings with the SEC.
All currency is expressed in Canadian dollars unless otherwise indicated.
For further information, please contact:
Investor Inquiries:
Rob Knowles
Manager, Investor Relations
Husky Energy Inc.
587-747-2116
Media Inquiries:
Mel Duvall
Manager, Media & Issues
Husky Energy Inc.
403-513-7602
