CALGARY, ALBERTA–(Marketwired – Oct. 24, 2013) – Husky Energy (TSX:HSE) continued to drive forward its growth plans in the third quarter as it announced a significant oil discovery offshore Newfoundland and Labrador and advanced the landmark Liwan Gas Project in the Asia Pacific Region closer to first production.
“Our business continues to deliver consistent results across the board,” said CEO Asim Ghosh. “We are hitting our targets and making steady progress towards executing our important milestones.”
Cash flow from operations was approximately $1.35 billion, compared to $1.27 billion in the third quarter of 2012. Net earnings of $512 million were comparable to $526 million in the same period last year.
Total Upstream production was approximately 309,000 barrels of oil equivalent per day (boe/day). This takes into account the scheduled six-day routine maintenance program on the SeaRose Floating Production, Storage and Offloading (FPSO) vessel as well as an ongoing planned reduction in dry gas production. Total oil and liquids production was 224,000 barrels per day (bbls/day), compared to 194,000 bbls/day in the third quarter of 2012, which reflects the planned SeaRose FPSO turnaround a year ago and increased heavy oil thermal production.
Downstream refineries and the Lloydminster Upgrader realized average throughputs of about 300,000 barrels per day (bbls/day), which takes into account a scheduled 45-day shutdown of the Upgrader for routine maintenance.
The Liwan Gas Project is more than 95 percent complete with commissioning work underway on the central platform and the onshore gas plant. The project is on schedule for first production in the coming months.
Husky and its partner continue to assess the commercial potential of the recent discoveries at Bay du Nord, Harpoon and Mizzen in the Atlantic Region. Husky has a 35 percent working interest in all three discoveries.
- Net earnings were $512 million, or $0.52 per share (diluted), compared to $526 million, or $0.53 per share (diluted) in the third quarter of 2012.
- Cash flow from operations was $1.35 billion, or $1.37 per share (diluted), compared with $1.27 billion, or $1.29 per share (diluted) in the third quarter of 2012.
- Total Upstream production was approximately 309,000 boe/day, up from approximately 285,000 boe/day in the third quarter of 2012.
- Construction is nearly 95 percent complete at the 3,500 bbls/day Sandall heavy oil thermal project, with first production anticipated in the first half of 2014.
- Four drilling rigs are dedicated to the Ansell liquids-rich gas resource play development.
- Field facility construction for Phase 1 of the Sunrise Energy Project is in the final stages with the overall project approximately 80 percent complete and on track to start up in the second half of 2014.
- A benefits agreement was concluded with the Government of Newfoundland and Labrador for the West White Rose development, and detailed engineering is proceeding for a fixed wellhead platform.
FINANCIAL AND OPERATIONAL HIGHLIGHTS
|Three Months Ended||Nine Months Ended|
|1) Daily Production, before royalties|
|Total Equivalent Production (mboe/day)||309||310||285||313||296|
|Crude Oil and NGLs (mbbls/day)||224||226||194||227||202|
|Natural Gas (mmcf/day)||506||505||545||515.8||564|
|2) Total Upstream Netback ($/boe) (1)||46.15||38.32||30.08||38.86||34.83|
|3) Refinery and Upgrader Throughput (mbbls/day)||300||317||328||314||325|
|4) Cash Flow from Operations(2) (Cdn $ millions)||1,347||1,449||1,271||4,079||3,596|
|Per Common Share – Basic ($/share)||1.37||1.47||1.29||4.15||3.69|
|Per Common Share – Diluted ($/share)||1.37||1.47||1.29||4.15||3.69|
|5) Net Earnings (Cdn $ millions)||512||605||526||1,652||1,548|
|Per Common Share – Basic ($/share)||0.52||0.61||0.53||1.67||1.58|
|Per Common Share – Diluted ($/share)||0.52||0.59||0.53||1.66||1.57|
|6) Adjusted Net Earnings(2) (Cdn $ millions)||544||610||512||1,701||1,523|
|Per Common Share – Basic ($/share)||0.55||0.62||0.52||1.73||1.56|
|Per Common Share – Diluted ($/share)||0.55||0.62||0.52||1.73||1.56|
|7) Capital Investment, including acquisitions (Cdn $ millions)||1,407||932||1,252||3,491||3,228|
|Per Common Share ($/share)||0.30||0.30||0.30||0.90||0.90|
|(1)||Upstream Netback includes results from Upstream Exploration and Production and excludes Upstream Infrastructure and Marketing.|
|(2)||Cash Flow from Operations and Adjusted Net Earnings are non-GAAP measures. Refer to the Q3 MD&A, Section 11 for reconciliation.|
Third quarter production of approximately 309,000 boe/day reflected a planned six-day shutdown of the SeaRose FPSO in July to tie in equipment for the South White Rose satellite extension. Third-party infrastructure outages and downtime in Western Canada continued to create production constraints that are anticipated to last through the end of the year.
The partner-operated Terra Nova FPSO began an 11-week maintenance offstation late in the quarter. Husky has a 13 percent working interest in Terra Nova and together with outages earlier in the year, the cumulative annual production impact is approximately 2,100 bbls/day.
The Lloydminster Upgrader successfully concluded a planned turnaround in mid-October and has resumed normal production.
“Through the year, we have continued to redirect capital from dry gas to higher-netback resource play opportunities, which changes our previous annual guidance range for gas to a range of 500 and 520 million cubic feet per day,” said CFO Alister Cowan. “Even with the impacts from the Terra Nova outages and planned lower dry gas production, we still expect to stay within our overall guidance range.”
In the Downstream business, significantly lower market crack spreads had an impact on refining margins in the third quarter.
Average realized pricing for the Company’s crude oil, natural gas liquids and bitumen in the third quarter was $93.23 per barrel, compared to $70.14 per barrel in the third quarter of 2012. U.S. realized refining margins declined to an average U.S. $11.86 per barrel compared to U.S. $24.36 per barrel in the third quarter of 2012.
KEY AREA SUMMARY AND GROWTH UPDATE
THE FOUNDATION BUSINESS
- Heavy Oil
Consistent performance from the Company’s Heavy Oil business resulted in production of approximately 123,000 bbls/day, compared to approximately 115,000 bbls/day in the third quarter of 2012. Total production from thermal developments, including Tucker, was approximately 48,000 bbls/day compared to approximately 37,800 bbls/day a year ago.
The 3,500 bbls/day Sandall thermal development is now approximately 95 percent complete, with first production planned in the first half of 2014.
Design and construction continued at the 10,000 bbls/day commercial thermal project at Rush Lake, with commissioning scheduled in mid-2015. Results from the two-well pair pilot are continuing to meet expectations.
Forty-five horizontal heavy oil wells were drilled in the third quarter, with 91 wells drilled to date out of a planned 140-well program for 2013. Ninety-three wells were drilled using Cold Heavy Oil Production with Sand (CHOPS), with 152 drilled to date as part of a planned 200-well program this year.
- Western Canada
Gas Resource Plays
Drilling continued with a four-rig program at the Ansell liquids-rich gas play. Twenty wells have been completed at Ansell to date in 2013.
Well completion activities are underway at the first four-well pad at Kaybob in the Duvernay play, with first production expected in the early 2014 timeframe. Drilling began on two additional wells on a second well pad.
Oil Resource Plays
Thirty-seven wells were drilled on the Bakken, Viking, Cardium and Lower Shaunavon oil resource plays, bringing the total number of wells drilled across the portfolio to 85 (gross) for 2013. Nineteen oil resource wells were completed over the third quarter.
Construction of an all-season access road is being finalized at the Slater River Canol play in the Northwest Territories. A proposed summer 2014 program for two vertical wells is awaiting final approval from regulatory authorities.
- Asia Pacific Region
The Liwan Gas Project is nearing completion with first production planned in the coming months. Commissioning of the onshore gas plant and shallow water central platform is underway and construction is continuing on the deepwater facilities to connect the nine wells and the pipeline to the platform.
Work is advancing on the Liuhua 34-2 field, which is scheduled to be tied into the main Liwan 3-1 deepwater facilities in the second half of 2014.
Natural gas from the fields will be processed at an onshore gas plant and sold to the mainland China market. Fixed-price sales agreements are in place for all of the planned production from both fields, while negotiations for the Liuhua 29-1 field gas continue.
Offshore Taiwan, work has commenced on a two-dimensional seismic survey on a deepwater exploration block located off the island’s southwest coast.
- Oil Sands
The 60,000 bbls/day (30,000 bbls/day net) first phase of the Sunrise Energy Project is approximately 80 percent complete as it advances towards initial production in late 2014.
Work continued on the Central Processing Facility (CPF) with all module fabrication completed and major equipment installed. Commissioning is underway for the first two of eight well pads, with the rest targeted for completion by the end of the year. Construction of the operations control centre is progressing as planned.
- Atlantic Region
Husky and its partner announced a significant discovery of light, high-quality oil at the Bay du Nord prospect approximately 500 kilometres northeast of St. John’s, Newfoundland and Labrador.
The well is the third discovery in the deepwater Flemish Pass Basin and further advances the Company’s exploration and development program in the Atlantic Region. Best estimate contingent resources are estimated by Husky at 400 million barrels (on a 100 percent working interest basis) as of September 23, 2013. Additional prospective resources have been identified and further evaluation is planned. Husky has a 35 percent working interest in the Bay du Nord, Harpoon and Mizzen discoveries. Statoil is the operator.
The Company continued to develop its White Rose satellite fields. Gas injection at the South White Rose extension, which is expected to enhance production, is scheduled to begin in the fourth quarter of 2013. The Company’s proved plus probable plus possible reserves are 20 million barrels of oil (16.8 million barrels probable and 3.1 million barrels possible, Husky W.I. share, as of December 31, 2012). Production from South White Rose will be tied back to the SeaRose FPSO vessel, with first oil anticipated by the end of 2014.
A benefits agreement has been signed with the Government of Newfoundland and Labrador for the West White Rose development. Detailed engineering is underway to build a fixed wellhead platform, with first oil planned in the 2017 timeframe.
Drilling has commenced on the Company’s fifth production well at the North Amethyst subsea tieback, while a fourth water injection well was completed and brought online in the third quarter.
Hydrocarbons were discovered at a Husky-operated step-out well at Northwest White Rose and results continue to be evaluated.
Preliminary design work has started on a proposed upgrading project at the Lima, Ohio Refinery to process up to 40,000 bbls/day of Western Canadian heavy oil, while maintaining the capability to refine lighter crudes.
By increasing the flexibility of its crude feedstock options, product range and the markets it is able to access, the Company is improving its ability to respond more quickly and efficiently to the market.
At the partner-operated refinery in Toledo, Ohio, work continued on a Hydrotreater Recycle Gas Processor to improve operational integrity and plant performance. The project is scheduled for completion in 2014.
The Board of Directors has declared a quarterly dividend of $0.30 (Canadian) per share on its common shares for the three-month period ending September 30, 2013. The dividend will be payable on January 2, 2014 to shareholders of record at the close of business on November 28, 2013.
A regular quarterly dividend on the 4.45 percent Cumulative Redeemable Preferred Shares, Series 1 (the “Series 1 Preferred Shares”) will be paid for the period October 1, 2013 to December 31, 2013. The dividend of $0.27813 per Series 1 Preferred Share will be payable on December 31, 2013 to holders of record at the close of business on November 28, 2013.
A conference call will be held on Thursday, October 24 at 10 a.m. Mountain Time (12 p.m. Eastern Time) to discuss Husky’s third quarter results. To listen live, please call one of the following numbers:
|Canada and U.S. Toll Free:||1-800-319-4610|
|Outside Canada and U.S.:||1-604-638-5340|
CEO Asim Ghosh, COO Rob Peabody, CFO Alister Cowan and Senior Downstream VP Bob Baird will participate in the call. To listen to a recording of the call, available at 12 p.m. Mountain Time on October 24, please call one of the following numbers:
|Canada and U.S. Toll Free:||1-800-319-6413|
|Outside Canada and U.S.:||1-604-638-9010|
|Passcode:||2658 followed by the # sign|
|Duration:||Available until November 24, 2013|
An audio webcast of the conference call will be available for approximately 90 days at www.huskyenergy.com under Investor Relations.
Husky Energy is one of Canada’s largest integrated energy companies. It is headquartered in Calgary, Alberta, Canada and is publicly traded on the Toronto Stock Exchange under the symbol HSE and HSE.PR.A. More information is available at www.huskyenergy.com
Certain statements in this news release are forward-looking statements and information (collectively “forward-looking statements”), within the meaning of the applicable Canadian securities legislation, Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended. The forward-looking statements contained in this new release are forward-looking and not historical facts.
Such forward-looking statements are based on the Company’s current expectations, estimates, projections and assumptions that were made by the Company in light of its experience and its perception of historical trends. Further, such forward-looking statements are subject to risks, uncertainties and other factors, some of which are beyond the Company’s control and difficult to predict. Accordingly, these factors could cause actual results or outcomes to differ materially from those expressed or projected in the forward-looking statements.
Some of the forward-looking statements may be identified by statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as “will likely result”, “are expected to”, “will continue”, “is anticipated”, “is targeting”, “estimated”, “intend”, “plan”, “projection”, “could”, “aim”, “vision”, “goals”, “objective”, “target”, “schedules” and “outlook”). In particular, forward-looking statements in this news release include, but are not limited to, references to:
- with respect to the business, operations and results of the Company generally: the Company’s general strategic plans and growth strategies; the anticipated duration of production constraints created by third-party infrastructure outages and downtime in Western Canada; and expected effect of reduced dry gas production and redirected capital on the Company’s gas production as compared with the Company’s previously issued guidance range for gas;
- with respect to the Company’s Asia Pacific region: planned timing of first production at the Company’s Liwan Gas Project; processing and sales plans for natural gas produced from the Company’s Liwan Gas Project; and scheduled timing of tie-in at the Company’s Liuhua 34-2 field;
- with respect to the Company’s Atlantic region: scheduled timing of commencement, and anticipated benefits, of gas injection at the Company’s South White Rose extension project; anticipated timing of first oil production from the Company’s South White Rose extension project, along with tie-back plans for such production; expected duration of a planned maintenance offstation at the Terra Nova FPSO; and planned timing of first production at the Company’s West White Rose development;
- with respect to the Company’s Oil Sands properties: scheduled timing of first production at the Company’s Sunrise Energy Project; and scheduled timing of completion of construction of field facilities at the Company’s Sunrise Energy Project;
- with respect to the Company’s Heavy Oil properties: scheduled timing of first production, and anticipated volumes of production, at the Company’s Sandall heavy oil thermal development project; expected timing of commissioning and volumes of production for the Company’s Rush Lake thermal development project; and the Company’s horizontal and CHOPS drilling programs for 2013;
- with respect to the Company’s Western Canadian oil and gas resource plays: the Company’s 2014 drilling program at its Canol Shale project in the Northwest Territories; and anticipated timing of production from the Company’s Kaybob project in the Duvernay play; and
- with respect to the Company’s Downstream operating segment: plans to increase the processing capability of the Lima, Ohio refinery and the expected benefits of this increase; scheduled timing of completion of a Hydrotreater Recycle Gas Compressor Project at the BP-Husky Toledo, Ohio refinery; and anticipated benefits of a feedstock flexibility project at the BP-Husky Toledo, Ohio refinery.
In addition, statements relating to “reserves” and “resources” are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves or resources described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of reserves and resources and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary from reserve, resource and production estimates.
Although the Company believes that the expectations reflected by the forward-looking statements presented in this news release are reasonable, the Company’s forward-looking statements have been based on assumptions and factors concerning future events that may prove to be inaccurate. Those assumptions and factors are based on information currently available to the Company about itself and the businesses in which it operates. Information used in developing forward-looking statements has been acquired from various sources including third-party consultants, suppliers, regulators and other sources.
Because actual results or outcomes could differ materially from those expressed in any forward-looking statements, investors should not place undue reliance on any such forward-looking statements. By their nature, forward-looking statements involve numerous assumptions, inherent risks and uncertainties, both general and specific, which contribute to the possibility that the predicted outcomes will not occur. Some of these risks, uncertainties and other factors are similar to those faced by other oil and gas companies and some are unique to Husky.
The Company’s Annual Information Form for the year ended December 31, 2012 and other documents filed with securities regulatory authorities (accessible through the SEDAR website www.sedar.com and the EDGAR website www.sec.gov) describe the risks, material assumptions and other factors that could influence actual results and are incorporated herein by reference.
Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by applicable securities laws, the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company’s course of action would depend upon its assessment of the future considering all information then available.
Disclosure of Oil and Gas Information
The Company uses the terms barrels of oil equivalent (“boe”), which is calculated on an energy equivalence basis whereby one barrel of crude oil is equivalent to six thousand cubic feet of natural gas. Readers are cautioned that the term boe may be misleading, particularly if used in isolation. This measure is primarily applicable at the burner tip and does not represent value equivalence at the wellhead.
The Company has disclosed possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of proved plus probable plus possible reserves. There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.
The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation. The Company has disclosed its total reserves in Canada in its Annual Information Form for the year ended December 31, 2012, which reserves disclosure is incorporated by reference herein.
The Company has disclosed best-estimate contingent resources in this news release. Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters, or a lack of markets. There is no certainty that it will be commercially viable to produce any portion of the contingent resources.
Best estimate as it relates to resources is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Estimates of contingent resources have not been adjusted for risk based on the chance of development. There is no certainty as to the timing of such development. For movement of resources to reserves categories, all projects must have an economic depletion plan and may require, among other things: (i) additional delineation drilling for unrisked contingent resources; (ii) regulatory approvals; and (iii) Company and partner approvals to proceed with development.
Specific contingencies preventing the classification of contingent resources at the Company’s Atlantic Region discoveries as reserves include additional delineation drilling, well testing, facility design, preparation of firm development plans, regulatory applications, Company and partner approvals.
Positive and negative factors relevant to the estimate of Atlantic Region resources include water depth and distance from existing infrastructure.
The Company has disclosed prospective resources in this news release. Prospective resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. Prospective resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be subclassified based on project maturity. There is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.”
Note to U.S. Readers
The Company reports its reserves and resources information in accordance with Canadian practices and specifically in accordance with National Instrument 51-101, “Standards of Disclosure for Oil and Gas Disclosure”, adopted by the Canadian securities regulators. Because the Company is permitted to prepare its reserves and resources information in accordance with Canadian disclosure requirements, it uses certain terms in this news release, such as “best estimate contingent resources” and “prospective resources” that U.S. oil and gas companies generally do not include or may be prohibited from including in their filings with the SEC.
Manager, Investor Relations
Husky Energy Inc.
Manager, Media & Issues
Husky Energy Inc.