May 5, 2017 - 6:00 AM EDT
Print Email Article Font Down Font Up Charts

Husky Energy Reports 2017 First Quarter Results

CALGARY, AB--(Marketwired - May 05, 2017) - Husky Energy Inc. (TSX: HSE) -- Good operational performance in the first quarter delivered funds from operations of $709 million, a 63 percent increase compared to a year ago, and free cash flow of $325 million.

"Our consistently improving performance over recent quarters has delivered increased free cash flow, demonstrating that the structural transformation of our business has reached critical mass," said CEO Rob Peabody.

"This moves us closer to our objective of returning cash to shareholders as the market stabilizes, while continuing to invest in a deep portfolio of projects."

First quarter highlights included:

  • Funds from operations were $709 million and free cash flow was $325 million.
  • Net earnings were $71 million, an increase of $529 million compared to the same period in 2016.
  • Total net bitumen production from thermal projects averaged 121,000 barrels per day (bbls/day), up 47 percent over Q1 2016. This represented 36 percent of total production.
  • The three most recent Lloyd thermal projects were delivered with capital efficiencies of about $25,000 per flowing barrel and had average operating costs of $8.23 per barrel in the quarter.
  • The Sunrise Energy Project is now producing 40,000 bbls/day gross (20,000 bbls/day net to Husky), with production from 55 well pairs averaging 730 bbls/day.
  • To date, the Company has signed agreements for the sale of about 3,300 barrels of oil equivalent per day (boe/day) in Western Canada for $88 million in gross proceeds.
  • Canadian Downstream ran at 97 percent capacity and took advantage of wider differentials to generate EBIT of $86 million.
  • Increased production at the Liwan Gas Project contributed to an operating netback of $64.43/boe and generated $184 million of EBITDA in the Asia Pacific business.


Overall average Upstream production was 334,000 boe/day, up from 327,000 boe/day in the prior quarter. That compares to 341,000 boe/day in the first quarter of 2016. Production reflected the disposition in 2016 of approximately 32,000 boe/day of production in Western Canada, largely offset by growing thermal production and increased volumes from the Liwan Gas Project.

Total upgrading and refining throughputs averaged 367,000 bbls/day, compared to 314,000 bbls/day in the same quarter last year.

WTI prices averaged $51.91 US per barrel compared to $33.45 US per barrel in the first quarter of 2016.

Average realized pricing for total Upstream production was $41.58 per boe, compared to $25.02 per boe in the same quarter the year before. This includes average realized gas pricing of $13.31 per thousand cubic feet (mcf) for sales gas at Liwan.

The Chicago 3:2:1 crack spread averaged $11.22 US per barrel compared to $9.23 US per barrel in the first quarter of 2016. Average realized U.S. refining margins were $8.33 US per barrel compared to $3.76 US per barrel a year ago.

Overall average Upstream operating costs were $13.75 per barrel.

Funds from operations were $709 million, compared to $434 million in the first quarter of 2016.

Capital expenditures were $384 million. Free cash flow was $325 million.

Net earnings were $71 million, compared to a loss of $458 million a year ago, reflecting higher commodity prices, increased production from thermal projects and Liwan, and higher throughputs and realized refining margins in both the Canadian and U.S. downstream operations.

   Three Months Ended
   Mar. 31
 Dec. 31
 Mar. 31
1) Daily Production, before royalties         
 Total Equivalent Production (mboe/day)  334  327  341
 Crude Oil and NGLs (mbbls/day)  244  235  238
 Natural Gas (mmcf/day)  543  555  619
2) Upstream Operating Netback ($/boe)(1)(2)  24.17  22.32  9.68
3) Refinery and Upgrader Throughput (mbbls/day)  367  351  314
4) Funds from Operations(2) ($ millions)  709  670  434
 Per Common Share - Basic ($/share)  0.71  0.67  0.43
 Per Common Share - Diluted ($/share) 0.71 0.67 0.43
5) Net Earnings (loss) ($ millions)  71  186  (458)
 Per Common Share - Basic ($/share) 0.06 0.19 (0.47)
 Per Common Share - Diluted ($/share) 0.06 0.19 (0.47)
6) Adjusted Net Earnings (loss)(2) ($ millions)  71  (6)  (458)
7) Capital Investment, including acquisitions ($ millions)  384  391  410
8) Net Debt(2)($ billions)  3.8  4.0  7.0

(1) Operating netback includes results from Upstream Exploration and Production and excludes Upstream Infrastructure and Marketing.
(2) Refer to the "Non-GAAP Measures" advisory in this news release.


Thermal Projects

Strong performance from the Edam East, Vawn and Edam West Lloyd thermal projects contributed to overall average net thermal bitumen production of 121,000 bbls/day, including the Tucker Thermal Project and Sunrise. Overall thermal operating costs were $11.83 per barrel in the quarter.

The Edam East, Vawn and Edam West developments, which came on production in 2016, are producing at 20 percent above design capacity, averaging 30,000 bbls/day. Average operating costs for the three projects were $8.23 per barrel in the quarter.

Construction continued to advance at the 10,000 bbls/day Rush Lake 2 Lloyd thermal project, with first oil expected in the first half of 2019. Open houses were held for the sanctioned 10,000 bbls/day Lloyd thermal projects at Dee Valley, Spruce Lake North and Spruce Lake Central, advancing the projects toward regulatory approval.

At the Tucker Thermal Project, first production from a new eight-well pad began in the quarter and drilling continued on an additional 15-well pad. Production from Tucker is anticipated to ramp up through 2017 and 2018 towards 30,000 bbls/day.

Gross production at Sunrise averaged 35,800 bbls/day (17,900 bbls/day net to Husky) in the quarter, up about six percent from the fourth quarter. Current production has reached 40,000 bbls/day (20,000 bbls/day net to Husky), with average per well pair production of about 730 bbls/day. Work is progressing to tie in 14 new well pairs, and steaming is expected to commence later this year.

Western Canada Resource Plays

To date, the Company has signed purchase and sales agreements for the sale of about 3,300 boe/day of production in Western Canada for $88 million in gross proceeds.

The Western Canada business is moving ahead with increased capital efficiency. 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 targeting the Wilrich formation in the Ansell and Kakwa areas is underway. A drilling program targeting the oil and liquids-rich Montney formation in the Wembley and Karr areas has commenced.


Engineering work continued on the proposed asphalt refinery, which would double Husky's asphalt production capacity. An open house on the project was held in March as part of the regulatory process.

Upgrading and refining throughputs averaged 367,000 bbls/day, contributing to overall capacity utilization of 95.5 percent.

Asia Pacific


At the liquids-rich BD Project offshore Indonesia, preparations are being finalized for first production, including plans to commission the floating production, storage and offloading (FPSO) vessel. The project is expected to ramp up to its full sales gas rate in the second half of 2017, with a gross sales production target of 100 million cubic feet per day (mmcf/day) of gas (40 mmcf/day net to Husky) and 6,000 bbls/day of liquids (2,400 bbls/day net to Husky).

At the MDA-MBH fields, platform construction is more than 40 percent complete. A contract for the floating production unit is awaiting final government approval. First gas is expected in the 2018-2019 timeframe, with an additional shallow water field at MDK expected to be tied in during the same period.

Total gross sales gas volumes from BD, MDA-MBH and MDK are expected to be approximately 250 mmcf/day of gas (100 mmcf/day net to Husky) and 6,000 bbls/day of associated liquids (2,400 bbls/day net to Husky) once production is fully ramped up.


At the Liwan Gas Project, gross sales gas volumes averaged 272 mmcf/day, with associated liquids production averaging 12,500 bbls/day. The Company realized pricing of $13.31 per mcf for its sales gas production.

In April, Husky signed a production sharing contract for Block 16/25, located in the Pearl River Mouth Basin. The Company expects to drill two exploration wells on the shallow water block during the 2018 timeframe, in conjunction with two planned exploration wells at the nearby Block 15/33.

Negotiations are progressing on a fixed-price gas sales agreement for the Liuhua 29-1 field. Project sanction is anticipated in the second half of 2017, subject to a final price agreement.


A new infill well at North Amethyst began production in the quarter, with peak production of 8,600 bbls/day net to Husky. A second well is planned in 2017 at White Rose, with the combined net peak production expected to be about 15,000 bbls/day. Both wells will be tied back to the SeaRose FPSO, providing for improved capital efficiencies.

Two exploration wells are scheduled to be drilled in the Flemish Pass Basin beginning in mid-2017.

A final investment decision on the West White Rose Project will be considered this year.

Near and Mid-Term Project Status

Thermal Developments  
Tucker Thermal Project Additional eight-well pad on production
Tucker Thermal Project Additional 15-well pad; first oil in first half of 2018
Sunrise Energy Project 14 new well pairs; first oil around year end 2017
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 Resource Plays  
16-well drilling program Under way
Exploratory Montney drilling program Under way
Lima Refinery 40,000 bbls/day Crude Oil Flexibility Project 10,000 bbls/day online, completion in 2018
Lloydminster Asphalt Project Sanction consideration
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 Sales gas contract negotiations in progress
Two White Rose infill wells On production and Q4 2017
West White Rose Project Final investment decision consideration in 2017



  • 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.


  • A four-week turnaround at the Lloydminster asphalt refinery is underway and expected to be completed the week of May 8.
  • The Lloydminster Upgrader will undergo a seven-week turnaround beginning in the second quarter.
  • A five-week partial turnaround is scheduled at the Lima Refinery in the fourth quarter.


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 June 30, 2017. The dividends will be payable on June 30, 2017 to holders of record at the close of business on June 12, 2017.

Share Series  Dividend Type  Rate (%)  Dividend Paid ($/share)
Series 1  Regular  2.404  $0.15025
Series 2  Regular  2.210  $0.13775
Series 3  Regular  4.50  $0.28125
Series 5  Regular  4.50  $0.28125
Series 7  Regular  4.60  $0.28750


A conference call will take place on Friday, May 5 at 8 a.m. Mountain Time (10 a.m. Eastern Time) to discuss the Company's first quarter results. CEO Rob Peabody, CFO Jon McKenzie and COO Rob Symonds will participate in the call.

To listen live:
Canada and U.S. Toll Free: 1-800-319-4610
Outside Canada and U.S.: 1-604-638-5340

To listen to a recording (after 10 a.m. on May 5)
Canada and U.S. Toll Free: 1-800-319-6413
Outside Canada and U.S.: 1-604-638-9010
Passcode: 1316
Duration: Available until June 5, 2017
Audio webcast: Available for 90 days at

Following the conference call, the Company will hold its Annual Meeting of Shareholders at 10:30 a.m. (Mountain Time) in the Palomino Room at the BMO Centre, 20 Roundup Way S.E., Calgary, Alberta.

A live webcast of the meeting will be available at under Investor Relations. The archived webcasts of the conference call and the meeting will be available for approximately 90 days.

Husky Energy is a Canadian-based integrated energy company. 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


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", "is 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 Thermal Developments: production expectations for the Tucker Thermal Project for 2017 and 2018; the anticipated timing of first oil from and design capacities of the Tucker 15-well pad, Rush Lake 2, Dee Valley, Spruce Lake North and Spruce Lake Central thermal projects; the work to tie in 14 new well pairs at Sunrise; and the expected timing of first oil and commencement of steaming at the new well pairs at Sunrise;
  • with respect to the Company's Asia Pacific region: the expected timing of ramp-up to full gas sales rate at the BD field; the expected timing of first gas at the MDA-MBH fields; the expected timing of the tie-in of an additional shallow water field at the MDK field; anticipated combined gross volumes from the BD, MDA-MBH and MDK fields once production is fully ramped up; drilling plans at Block 15/33 and Block 16/25; and the expected timing of project sanction for the Liuhua 29-1 field;
  • with respect to the Company's Atlantic region: drilling plans at White Rose for 2017; anticipated combined net peak production of the new infill well at North Amethyst and the planned well at White Rose; drilling plans in the Flemish Pass for 2017; and the timing to consider the sanction of the West White Rose project.
  • with respect to the Company's Western Canada Resource Plays: expected proceeds of sale of production; and drilling plans;
  • with respect to the Company's Upstream operating segment, the anticipated timing and duration of turnarounds at the SeaRose FPSO and the Terra Nova FPSO; and
  • with respect to the Company's Downstream operating segment: the anticipated timing for completion of the crude oil flexibility project at the Lima Refinery; and the anticipated timing and duration of turnarounds at the Lloydminster asphalt refinery, the Lloydminster Upgrader and the Lima Refinery.

There are numerous uncertainties inherent in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary from 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 and regulators, among others.

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 the Company.

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 and the EDGAR website describe risks, material assumptions and other factors that could influence actual results and are incorporated herein by reference.

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 management's assessment of the future considering all information available to it at the relevant time. 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.

Non-GAAP Measures

This news release contains references to the terms "funds from operations", "free cash flow" and "adjusted net earnings (loss)", which do not have standardized meanings prescribed by International Financial Reporting Standards ("IFRS"). Refer to "Non-GAAP Measures" in section 11 of the Company's Management's Discussion and Analysis for the year ended December 31, 2016.

This news release also contains references to "operating netback" and "net debt", which do not have standardized meanings prescribed by IFRS and are therefore unlikely to be comparable to similar measures presented by other issuers.

Operating netback is a common non-GAAP measure used in the oil and gas industry. This measure assists management and investors to evaluate the specific operating performance by product at the oil and gas lease level. Operating netback is calculated as gross revenue less royalties, production and operating and transportation costs on a per unit basis.

Net debt is a non-GAAP measure that equals total debt less cash and cash equivalents. Total debt is calculated as long-term debt, long-term debt due within one year and short-term debt. Net debt is considered to be a useful measure in assisting management and investors to evaluate the Company's financial strength.

The following table shows the reconciliation of total debt to net debt as at March 31, 2017 and December 31, 2016:

($ millions)  March 31, 2017  December 31, 2016
Short-term debt  200   200  
Long-term debt due within one year  400   403  
Long-term debt  5,453   4,736  
Total debt  6,053   5,339  
Cash and cash equivalents  (2,245 ) (1,319 )
Net Debt  3,808   4,020  

Disclosure of Oil and Gas Information

The Company uses the term "barrels of oil equivalent" (or "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.

Unless otherwise noted, projected and historical production volumes are presented on a net to Husky before royalties basis.

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.

Media Inquiries:

Mel Duvall
Manager, Media & Issues
Husky Energy Inc.

Source: Marketwired (Canada) (May 5, 2017 - 6:00 AM EDT)

News by QuoteMedia

Legal Notice