Husky Energy Announces 2016 Second Quarter Results

- July 22nd, 2016

CALGARY, AB –(Marketwired – July 22, 2016) – Husky Energy (TSX: HSE) made steady progress in the quarter against several objectives, including strengthening its balance sheet and further improving the quality of its production. “This is a milestone moment for the Company, as the elements of the transformation initiated six years ago are now largely … Continued

CALGARY, AB –(Marketwired – July 22, 2016) – Husky Energy (TSX: HSE) made steady progress in the quarter against several objectives, including strengthening its balance sheet and further improving the quality of its production.
“This is a milestone moment for the Company, as the elements of the transformation initiated six years ago are now largely in place,” said CEO Asim Ghosh. “We have fortified our balance sheet, reduced our earnings break-even oil price and lowered our sustaining and maintenance capital requirements.
“In short, we are now a highly resilient business better positioned to generate free cash flow even in a lower for longer oil price environment.”
The Company is in line to achieve and surpass its objective of less than two times net debt-to-cash flow from operations with the closing of several transactions, resulting in a balance sheet that is amongst the strongest in the industry. Upon the completion of the dispositions, net debt will be below $4.5 billion, compared to about $7 billion in the first quarter of 2016.
In addition, these initiatives advanced several strategic business objectives, including:
  • The new Husky Midstream Limited Partnership reduces overall infrastructure funding requirements associated with new thermal growth, while preserving tight integration with the Downstream assets. The transaction has now closed. It has delivered $1.7 billion in proceeds, with the sale price representing about 13 times the expected 2016 EBITDA of the assets.
  • The Western Canada operations are undergoing a strategic transformation. Fewer, more material plays are providing for a more capital efficient business with reduced sustaining capital requirements. Approximately 25,700 barrels of oil equivalent per day (boe/day) of production, including royalty interests, has been sold for about $1.2 billion.

Several projects were progressed in the second quarter, including:

  • The Edam East Lloyd Thermal Project came on production in mid-April and has surpassed its 10,000 barrels per day (bbls/day) design capacity.
  • First oil was achieved ahead of plan at the 10,000 bbls/day Vawn Lloyd Thermal Project, which is now producing about 5,500 bbls/day and ramping up ahead of schedule.
  • Steaming commenced at the 4,500 bbls/day Edam West Lloyd Thermal Project earlier than scheduled, with production on track for the third quarter.
  • The Tucker Thermal Project averaged about 20,000 bbls/day in June, up from 4,000 bbls/day at the end of 2010 when the current rejuvenation program began.
  • The Sunrise Energy Project was restarted in June following the Fort McMurray wildfires. Production continues to ramp up with recent volumes of more than 30,000 bbls/day.
  • An additional 18 Lloyd thermal projects have been identified for potential advancement.

With a focus on higher quality production, Husky requires less sustaining and maintenance capital while providing for improved margins and reduced cash flow variability.
Through these structural changes, by the end of 2016 the overall earnings break-even is expected to be sub-$40 US WTI. Annual sustaining and maintenance capital requirements are down significantly from a historical average of $3 billion. Upstream sustaining and maintenance capital requirements are down from $2.3 billion to $1.8 billion, while Downstream remains steady at about $700 million. These totals are expected to decrease further with continued improvements in the quality of production.
Several planned turnarounds were completed in the quarter, further improving efficiency and reliability.
In Upstream, a six-week turnaround was conducted at the partner-operated Terra Nova FPSO (floating production, storage and offloading) vessel, while a three-week turnaround was completed at the Ram River gas plant in Alberta. Offshore China, the Wenchang oil field underwent a one-week turnaround.
In Downstream, a major eight-week turnaround was completed at the Lima Refinery and a five-week turnaround was performed at the Prince George Refinery. At the partner-operated refinery in Toledo, a 10-week turnaround was recently completed and startup operations are under way. The refinery is now able to process about 65,000 bbls/day of Hi-TAN crude to support production from the Sunrise Energy Project, while maintaining its overall capacity.
Average Upstream production in the quarter was about 316,000 boe/day, reflecting planned turnarounds, the production interruption at Sunrise due to the Fort McMurray wildfires and reduced volumes from the Liwan Gas Project.
Even with the Western Canada dispositions of about 25,700 boe/day and lower sales volumes from Liwan, annual production guidance remains 315,000-345,000 boe/day, albeit at the lower end.
This is largely due to the consistent performance across the Upstream business, including strong results from the Lloyd thermal projects and the steady ramp ups at Sunrise and Tucker.
Throughputs at the refineries and Lloydminster Upgrader averaged 255,000 bbls/day, which takes planned turnarounds into account.
WTI prices averaged $45.59 US per barrel compared to $57.94 US per barrel in the second quarter of 2015. Average realized pricing for total Upstream production was $34.59 per boe, compared to $49.50 per boe in the second quarter of 2015.
Upstream operating costs were $13.90 ($10.79 US) per barrel compared to $15.72 ($12.78 US) per barrel a year ago, a reduction of 12 percent. The majority of these savings are expected to be sustainable due to the deliberate structural changes and efficiencies undertaken as part of Husky’s transformation.
Cash flow from operations was $488 million for the quarter, reflecting planned turnarounds, after-tax hedging losses of $79 million and an after-tax FIFO gain of $88 million.
Net earnings were a loss of $196 million, which takes into account the factors affecting cash flow as well as three non-cash items: a $71 million after-tax loss associated with the dispositions, a $12 million after-tax property impairment and $22 million in exploration and evaluation asset write-downs. Excluding the above non-recurring items, the adjusted net loss was $91 million.

Three Months Ended Six Months Ended
June 30
Mar 31
June 30
June 30
June 30
1) Daily Production, before royalties
Total Equivalent Production (mboe/day) 316 341 337 329 346
Crude Oil and NGLs (mbbls/day) 228 238 217 233 227
Natural Gas (mmcf/day) 529 619 722 574 719
2) Operating Netback ($/boe) (1)(2) 17.30 9.68 28.93 13.34 25.10
3) Refinery and Upgrader Throughput (mbbls/day) 255 314 319 284 309
4) Cash Flow from Operations(2) (Cdn $ millions) 488 434 1,177 922 2,015
Per Common Share – Basic ($/share) 0.49 0.43 1.20 0.92 2.05
Per Common Share – Diluted ($/share) 0.49 0.43 1.20 0.92 2.05
5) Net Earnings (Cdn $ millions) (196) (458) 120 (654) 311
Per Common Share – Basic ($/share) (0.20) (0.47) 0.11 (0.67) 0.30
Per Common Share – Diluted ($/share) (0.20) (0.47) 0.10 (0.67) 0.27
6) Adjusted Net Earnings (loss)(2) (91) (458) 124 (549) 315
7) Capital Investment, including acquisitions (Cdn $ millions) 595 410 727 1,005 1,547
8) Dividend Per Common Share ($/share) 0.00(3) 0.00(3) 0.30 0.00(3) 0.60
(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 Section 11 of the Q2 MD&A, which is incorporated herein by reference.
(3) The quarterly common share dividend remains suspended.

Area Summary
Heavy Oil
Thermal technology continues to fundamentally transform the heavy oil portfolio through the development of long life, low risk and capital efficient Lloyd thermal projects.
Three Lloyd thermal projects started up in the quarter, with combined design capacity of 24,500 bbls/day. Total Tucker and Lloyd thermal production is expected to be approximately 100,000 bbls/day once all three Lloyd projects are fully ramped up.
Western Canada
Approximately 25,700 boe/day of production, including royalty interests, was sold for about $1.2 billion. In addition, Husky obtained certain royalty transfers and lands in the Lloydminster region that will contribute to its growing thermal portfolio.
As a result of these transactions, sustaining and maintenance capital requirements are being further reduced and corporate asset retirement obligations are expected to be lowered by about $1.7 billion over the life of the assets, on an undiscounted basis.
Work continued on the initial stages of the crude oil flexibility project at the Lima Refinery, which will allow the refinery to process up to 40,000 bbls/day of heavy crude feedstock. Initial capacity of 8,000 bbls/day of heavy crude feedstock capability is expected to be available in the fourth quarter, with the full scope of the project scheduled to be completed in 2018.
Construction continued on the Saskatchewan Gathering System expansion, with work expected to be completed in the third quarter.
Regulatory approval was received for the creation of a single expanded truck transport fuel network of 160 sites. The larger national network is expected to better serve Canadian commercial and truck transport customers.
Asia Pacific Region
Husky’s discussions with CNOOC and its affiliated entities to resolve an issue related to the Liwan Gas Project have progressed to a framework for resolution. Further updates will be provided as the details are finalized.
Liwan gross gas sales averaged 161 million cubic feet per day (mmcf/day), with associated liquids sales of 9,200 bbls/day.
Husky continues to progress its Madura Strait natural gas developments.
The wellhead and pipeline infrastructure at the liquids-rich BD field is more than 75 percent complete, and drilling is ongoing on four wells as part of the initial development plan. Construction of an FPSO to process gas and liquids from the field is about 85 percent complete, with the remaining processing modules scheduled for installation in the next few months. First production is expected to commence in 2017, with a net production target of 40 mmcf/day gas and 2,400 bbls/day of associated liquids.
At the shallow water MDA-MBH and MDK gas fields, tendering is under way for engineering, procurement, construction and installation contracts. The fields will be developed in tandem and share infrastructure.
Combined net sales volumes from the BD, MDA-MBH and MDK fields are expected to be approximately 100 mmcf/day of gas and 2,400 bbls/day of associated liquids once the fields are fully ramped up in the 2018-2019 timeframe.
Oil Sands
The Sunrise Energy Project continues its steady ramp-up following the restart of operations in June. All 55 well pairs are back online and recent production is more than 30,000 bbls/day.
The steam-oil ratio continues to steadily improve towards the design SOR of 3.0 while the water-oil ratio is in line with the forecast 3.6-3.8 range.
Atlantic Region
Average net production was about 32,700 bbls/day, which takes into account a six-week turnaround at the partner-operated Terra Nova FPSO.
The Henry Goodrich rig has resumed operations at North Amethyst. The Hibernia formation well is forecast to achieve net peak production rates of 5,000 bbls/day, with first oil expected in the fall of 2016. The rig will also be used for further development drilling at the White Rose field.
In the Flemish Pass Basin, an exploration and appraisal program on the Bay du Nord discovery area has concluded. Two oil discoveries were made at the Bay de Verde and Baccalieu prospects, and Husky and its partner are planning the next steps.
Husky holds a 35 percent working interest in the Bay du Nord, Mizzen, Harpoon, Bay de Verde and Baccalieu discoveries.

  • A three-week turnaround is under way on the SeaRose FPSO, with net impacts expected to be approximately 8,000 bbls/day averaged over the third quarter.
  • At the Liwan Gas Project, the installation of a second deepwater pipeline to provide for backup flow capacity has been completed.


  • A 10-week turnaround was recently completed at the Toledo Refinery and startup operations are under way.

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 September 30, 2016. The dividends will be payable on September 30, 2016 to holders of record at the close of business on August 29, 2016.

Share Series Dividend Type Rate (%) Dividend Paid ($/share)
Series 1 Regular 2.404 $0.15025
Series 2 Regular 2.269 $0.14259
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, July 22 at 9 a.m. Mountain Time (11 a.m. Eastern Time) to discuss the Company’s second 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: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. July 22)Canada and U.S. Toll Free: 1-800-319-6413
Outside Canada and U.S.: 1-604-638-9010
Passcode: 00616 followed by # sign
Duration: Available until August 22, 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.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”, “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 expectations and objectives with respect to net debt to cash flow from operations; multiple of expected 2016 EBITDA from the select midstream assets represented by the sale price; forecasted earnings breakeven for year end 2016; expected further reduction in sustaining and maintenance capital requirements as a result of expected improvements in the production quality; the Company’s 2016 production guidance, including the expectation that annual production will be at the lower end of previously stated guidance; expectation that the operating costs per barrel savings that have been realized will be sustainable; and expected impact on sustaining and maintenance capital requirements and corporate asset retirement obligations by the Western Canada dispositions;
  • with respect to the Company’s Asia Pacific Region: planned timing of first production at, and targeted daily volumes of production from, the Company’s BD field; planned timing of first gas from the Madura Strait MDA-MBH and MDK fields; targeted 2018-2019 combined daily volumes of production from the Madura Strait developments; and timing of installation of remaining processing modules on the FPSO vessel to process gas and liquids from the BD field;
  • with respect to the Company’s Atlantic Region: anticipated timing of first oil and anticipated net peak daily production from the Company’s North Amethyst Hibernia well project; drilling plans for the Henry Goodrich at the White Rose field; and anticipated duration and impact on production of a turnaround on the SeaRose FPSO;
  • with respect to the Company’s Oil Sands properties: the Company’s forecasted water-oil ratio and steam-oil ratio for the Sunrise Energy Project;
  • with respect to the Company’s Heavy Oil properties: anticipated timing of first production from, and forecast design capacity of, the Company’s Edam West heavy oil thermal project; forecasted design capacity of the Company’s Edam East, Vawn and Rush Lake 2 heavy oil thermal projects; and forecasted thermal production from Tucker and Lloyd;
  • with respect to the Company’s Western Canadian oil and gas resource plays; the Company’s strategic plans for its Western Canada portfolio;
  • with respect to the Company’s Infrastructure and Marketing segment: expected timing of completion of the expansion of the Saskatchewan Gathering System; and
  • with respect to the Company’s Downstream operating segment: anticipated timing and benefits of the crude oil flexibility project at 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, 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 the term EBITDA, which is a non-GAAP measure. Refer to Section 11 of the Q2 MD&A, which is incorporated herein by reference.
Disclosure of Oil and Gas Information
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.
In this news release, the Company uses the term operating costs per barrel, which is consistent with other oil and gas producer’s disclosures, and is calculated by dividing total operating costs for the Company’s Heavy Oil thermal or non-thermal production, as applicable, by the total barrels of such thermal or non-thermal production, as applicable. The term is used to express operating costs on a per barrel basis that can be used for comparisons.
Steam-oil ratio (“SOR”) measures the average volume of steam required to produce a barrel of oil. Water-oil ratio (“WOR”) measures the average volume of water produced per a barrel of oil. These measures do not have any standardized meanings and should not be used to make comparisons to similar measures presented by other issuers.
Earnings break-even reflects the estimated WTI oil price per barrel priced in US dollars required in order to generate a net income of CAD $0 in the 12 month period ending December 31, 2016. This assumption is based on holding several variables constant throughout the period, including: foreign exchange rate, light-heavy oil differentials, realized refining margins, forecast utilization of downstream facilities, estimated production levels, and other factors consistent with normal oil and gas company operations. This measurement is used to assess the impact of changes in WTI oil prices to the net earnings of the Company and could impact future investment decisions.
Note to U.S. Readers
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.

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