CALGARY, AB–(Marketwired – February 12, 2015) – Husky Energy (TSX: HSE) continues to focus on efficiencies, manage its investment flows and maintain its strong balance sheet as it delivers its work program.
“We took a realistic approach with our 2015 business plan and continue to identify strategies to further support our balance sheet in today’s lower oil price environment,” said CEO Asim Ghosh. “We are continuing to position the Company for beyond this downturn as a low sustaining capital business. By the end of 2016, about half of our total production will be from low sustaining capital projects.”
The Company has further refined its capital plan to $3.0-3.1 billion from $3.4 billion. The savings are primarily related to the rescheduling of discretionary activities in Western Canada and other initiatives. Production for the year is anticipated to remain within the previously announced guidance range of 325,000 to 355,000 barrels of oil equivalent per day (boe/day).
In addition, about $400-600 million in operating cost efficiencies has been targeted, in large part through procurement and contract savings to be realized over the course of the year. This will include more effective partnering with suppliers, consolidation and standardization in services.
Near Term Growth Projects
Projects currently in development are progressing and are expected to add about 85,000 net barrels per day (bbls/day) by the end of 2016.
|Projects||Business||First Production||Forecast Net Peak Production (bbls/day)|
|Sunrise Energy Project Plant 1A||Oil Sands||Q1/15||15,000 (mid-2016)|
|South White Rose Extension||Atlantic Region||Mid-Year 2015||15,000|
|Sunrise Energy Project Plant 1B||Oil Sands||Q3/15||15,000 (late 2016)|
|North Amethyst Hibernia well||Atlantic Region||Q3/15||5,000|
|Rush Lake||Heavy Oil Thermal||Q3/15||10,000|
|Edam East||Heavy Oil Thermal||Q3/16||10,000|
|Edam West||Heavy Oil Thermal||Q4/16||3,500|
|Vawn||Heavy Oil Thermal||Q4/16||10,000|
2014 Operational Highlights
Annual Upstream production averaged 340,000 boe/day, an increase of approximately nine percent from the previous year. This included new production from Liwan and strong performance from heavy oil thermal developments.
The Company achieved several milestones that provide a firm foundation for future production and reserves growth.
- The 3,500 bbls/day Sandall heavy oil thermal development began production in early 2014 and exited the year at approximately 5,700 bbls/day.
- The Liwan Gas Project came online at the end of the first quarter of 2014.
- The Liuhua 34-2 field started up in the fourth quarter.
- The Sunrise Energy Project began steam injection. First oil is expected towards the end of the first quarter of 2015.
- Production from a suite of long life, high netback heavy oil thermal projects rose 21 percent year over year.
- An updated assessment of Husky’s heavy oil resources in the Lloydminster area at the end of 2014 significantly increased the overall best estimate contingent resources in the region from 107 million barrels to 1.9 billion barrels, of which 54 percent has the potential to be recovered using thermal technology. Total heavy oil initially in place is estimated to be 17 billion barrels, of which 16 billion barrels are discovered heavy oil initially in place.
Downstream throughputs were 318,000 bbls/day in 2014, comparable to 2013 volumes.
Reserves growth has outpaced production over the last four years. The average four-year proved reserve replacement ratio was 157 percent, excluding economic factors (143 percent including economic factors). In 2014, the average proved reserve replacement ratio was 115 percent, excluding economic factors (111 percent including economic factors).
At the end of 2014, the Company had total proved reserves before royalties of 1.3 billion barrels of oil equivalent (boe), probable reserves of 1.9 billion boe and best estimate contingent resources of 14.8 billion boe. The Company’s Oil Sands portfolio was responsible for 10.3 billion boe of the best estimate contingent resources total.
2014 Financial Highlights
Capital expenditures for 2014 were within guidance at $5.0 billion.
Cash flow from operations was $5.5 billion in 2014, compared to $5.2 billion in 2013. This reflected the startup of the Liwan fields and ongoing steady performance from heavy oil thermal projects.
Net earnings in 2014 before one-time charges were $2.0 billion, comparable to 2013. A non-cash impairment charge of $622 million after tax was recorded in the fourth quarter on mature assets in Western Canada related to reductions in the price forecast. Declining commodity prices and crack spreads during the year resulted in provisions of $135 million after tax to reduce inventory held in refining to net realizable value.
Including one-time charges, net earnings in 2014 were $1.3 billion. This also included a FIFO loss of $108 million after tax in U.S. Refining as a result of falling commodity prices.
In the fourth quarter, including one-time charges, the net loss was $603 million compared to net earnings of $177 million in the same period of 2013. Excluding one-time charges for asset impairments and a provision of $128 million after tax to reduce inventory to net realizable value in the quarter, net earnings were $147 million.
West Texas Intermediate (WTI) prices averaged $93.00 US per barrel in 2014 compared to $97.97 US per barrel in 2013. Average realized pricing for the Company’s total Upstream production in 2014 was $67.38 Cdn per barrel, compared to $61.96 Cdn a year ago.
U.S. refining Chicago market crack spreads averaged $17.28 US per barrel in 2014, compared to $21.30 US in 2013, while the realized U.S. refining margin averaged $9.37 US per barrel compared to $15.06 US a year ago.
|Three Months Ended||Twelve Months Ended|
|1)||Daily Production, before royalties|
|Total Equivalent Production (mboe/day)||360||341||308||340||312|
|Crude Oil and NGLs (mbbls/day)||243||229||224||237||227|
|Natural Gas (mmcf/day)||702||670||504||621||513|
|2)||Operating Netback ($/boe) (1)(2)||34.84||43.05||34.29||42.63||37.72|
|3)||Refinery and Upgrader Throughput (mbbls/day)||344||334||324||318||317|
|4)||Cash Flow from Operations(2) (Cdn $ millions)||1,145||1,341||1,143||5,535||5,222|
|Per Common Share – Basic ($/share)||1.16||1.36||1.16||5.63||5.31|
|Per Common Share – Diluted ($/share)||1.16||1.36||1.16||5.62||5.31|
|5)||Net Earnings /Loss (Cdn $ millions)||(603)||571||177||1,258||1,829|
|Per Common Share – Basic ($/share)||(0.62)||0.58||0.18||1.26||1.85|
|Per Common Share – Diluted ($/share)||(0.65)||0.52||0.18||1.20||1.85|
|6)||Capital Investment, including acquisitions (Cdn $ millions)||1,419||1,279||1,537||5,023||5,028|
|Per Common Share ($/share)||0.30||0.30||0.30||1.20||1.20|
|(1) Operating netback includes results from Upstream Exploration and Production and excludes Upstream Infrastructure and Marketing.|
|(2) Operating netback and cash flow from operations are non-GAAP measures. Refer to the Q4 MD&A, Section 11, which is incorporated herein by reference.|
KEY AREA SUMMARY
- Heavy Oil
Husky is advancing a series of long life, high netback heavy oil thermal projects that provide for higher oil recovery with low decline rates.
Annual thermal production averaged approximately 44,000 bbls/day in 2014, compared to 37,000 bbls/day in 2013 and about 18,000 bbls/day in 2010. This reflected strong performance from existing thermal projects and new production from the 3,500 bbls/day Sandall thermal development, which came online ahead of schedule in early 2014 and exited the year at an average rate of 5,700 bbls/day.
Construction is under way at the 10,000 bbls/day Rush Lake heavy oil thermal project, with first oil scheduled for the third quarter of 2015.
Site clearing, module construction and detailed engineering began at the 10,000 bbls/day thermal projects at Edam East and Vawn, with first oil planned in the third and fourth quarter of 2016, respectively. The 3,500 bbls/day Edam West thermal development remains on track for startup in the fourth quarter of 2016.
- Western Canada
The Company is high-grading its key resource plays in Western Canada at a measured pace. Overall production from resource plays in 2014 averaged about 34,000 boe/day.
The Ansell liquids-rich gas play is at the forefront of activity, with production volumes averaging 18,700 boe/day in the fourth quarter of 2014. Further drilling, completions and facility construction is currently under way.
The Company is pacing its oil resource development activity across the Western Canada portfolio.
Husky is working to further improve the flexibility of its feedstock, product range and market access to better support its Upstream crude and bitumen production.
Two 300,000-barrel storage tanks and associated pipe infrastructure have been completed and brought into service at Hardisty, Alberta, while the expansion of the South Saskatchewan gathering system is being progressed to accommodate the Company’s growing heavy oil thermal production.
- Asia Pacific Region
Production from the Liwan Gas Project continued to build over the year as the Liuhua 34-2 field was tied into the main Liwan field infrastructure and commenced production in December 2014.
Gas sales volumes from fixed price contracts rose to 265 million cubic feet per day (mmcf/day, gross) at the end of 2014.
The Company is advancing development work on four shallow water gas fields in the Madura Strait.
A contract has been signed to build and lease an FPSO vessel to develop the liquids-rich BD field. Construction of a wellhead platform and pipeline infrastructure for the BD field is under way with first gas planned in 2017.
Tender plans for the MDA and MBH natural gas fields received government approval and a gas sales agreement is under regulatory review. A Plan of Development was approved by government regulators for the MDK natural gas field. Production from all three fields is anticipated in the 2017-2018 timeframe.
Husky has a 40 percent interest in the Madura Strait developments.
- Oil Sands
Steam injection has commenced at the Sunrise Energy Project, with steam introduced into 25 of 55 well pairs to date. All facilities are performing as expected and first oil is anticipated towards the end of the first quarter of 2015.
A customized mobile drilling rig arrived on site in early January and has commenced work on a new sustaining pad. The rig provides for the closer spacing of wellheads, smaller drilling pads and fewer facilities, resulting in further efficiencies.
Pre-commissioning work continues on Plant 1B. Sunrise is expected to ramp up to full capacity of 60,000 bbls/day (30,000 bbls/day net to Husky) around the end of 2016.
Husky is the operator and has a 50 percent working interest in the project. The partner operates the jointly-owned
BP-Husky Toledo refinery, which will process Sunrise bitumen into various transportation fuels and other energy products.
- Atlantic Region
The Company is progressing its satellite developments in the Jeanne d’Arc Basin offshore Newfoundland and Labrador.
Development drilling has commenced at the South White Rose field. First oil is slated for the mid-2015 timeframe, with forecast net peak production of approximately 15,000 bbls/day (net).
At North Amethyst, a well targeting the deeper Hibernia formation beneath the main field is scheduled to be brought online in the third quarter of 2015, with production anticipated to increase to approximately 5,000 bbls/day (net).
In the Flemish Pass, an exploration and appraisal program in the area of the Bay du Nord discovery is progressing as expected.
Husky holds a 35 percent working interest in the Bay du Nord, Mizzen and Harpoon discoveries.
Q1 MAINTENANCE AND TURNAROUND PLANS
- Unplanned third-party turnarounds and outages in Western Canada are anticipated to continue in the first quarter.
- Production has resumed at the Lima refinery following an unplanned 10-day shutdown of operations. The refinery is running at about 80 percent of capacity. The extent and timetable for repairs to the isocracker is currently being assessed.
Husky Energy has made a $1 billion US payment on a $1.3 billion US capital contribution obligation due on December 31, 2015 to the BP-Husky Refining joint venture partner. By making the payment at this time, the Company expects to realize about $60 million US in interest savings. Further, the parties have agreed that the remaining $300 million US balance is to be paid over the next three years with final amounts due at the end of 2017.
The funds for the payment were raised through Husky’s 2014 commercial paper program and converted to U.S. dollars in the second half of last year.
The Board of Directors has declared a quarterly dividend of $0.30 (Canadian) per share on its common shares for the three-month period ended December 31, 2014. The dividend will be payable on April 1, 2015 to shareholders of record at the close of business on March 13, 2015.
A regular quarterly dividend payment on the 4.45 percent Cumulative Redeemable Preferred Shares, Series 1 (the “Series 1 Preferred Shares”) will be paid for the period January 1, 2015 to March 31, 2015. The dividend of $0.27813 per Series 1 Preferred Share will be payable on March 31, 2015 to holders of record at the close of business on March 13, 2015.
The initial quarterly dividend payment on the 4.50 percent Cumulative Redeemable Preferred Shares, Series 3 (the “Series 3 Preferred Shares”) will be paid for the period December 9, 2014 to March 31, 2015. The dividend of $0.34521 per Series 3 Preferred Share will be payable on March 31, 2015 to holders of record at the close of business on March 13, 2015.
For those holders of common shares who have not already done so and would like to accept to receive dividends in the form of common shares, they should inform Husky’s transfer agent, Computershare, via written notice in prescribed form on or before March 5, 2015. A link to an electronic copy of the Stock Dividend Confirmation Notice is available at www.investorcentre.com/husky
A conference call will take place on Thursday, February 12 at 10 a.m. Mountain Time (12 p.m. Eastern Time) to discuss Husky’s year-end and fourth 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, Acting CFO Darren Andruko and Downstream Senior VP Bob Baird will participate in the call. To listen to a recording of the call, available at 12 p.m. Mountain Time on February 12, 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 February 26, 2015
An audio webcast of the 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 its common shares are publicly traded on the Toronto Stock Exchange under the symbol HSE. 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 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 2015 capital plan; anticipated production guidance range for the year; anticipated range of operating cost efficiencies; and anticipated proportion of total production from low sustaining capital cost projects by the end of 2016; anticipated increases in production by the end of 2016; and the Company’s expected savings on interest resulting from the capital contribution;
- with respect to the Company’s Asia Pacific Region: planned timing of first gas from the Madura Strait BD, MDA, MBH and MDK fields;
- with respect to the Company’s Atlantic Region: anticipated timing of first production from, and forecast net peak daily production from, the Company’s South White Rose Extension project; anticipated timing of, and anticipated increase in production from, the North Amethyst Hibernia well project being brought online;
- with respect to the Company’s Oil Sands properties: anticipated timing of first production from, and forecast net peak daily production from, the Company’s Sunrise Energy Project Plant 1A and 1B; and anticipated timing of ramp-up to full capacity at Sunrise;
- with respect to the Company’s Heavy Oil properties: anticipated timing of first production from, and forecast net peak daily production from, the Company’s Rush Lake, Edam East, Edam West and Vawn heavy oil thermal projects; and
- with respect to the Company’s Western Canadian oil and gas resource plays: anticipated continuation of unplanned third-party turnarounds and outages in the area.
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 and 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, 2013 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
Unless otherwise stated, reserve and resource estimates in this news release have an effective date of December 31, 2014 and represent Husky’s share. Unless otherwise noted, historical production numbers given represent Husky’s share.
The Company uses the terms barrels of oil equivalent (“boe”), which is 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.
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 estimate of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.
The Company has disclosed best estimate contingent resources of 14.8 billion boe, which is comprised of 13.8 billion boe of crude oil and 6.2 tcf of natural gas. Of the total 11.5 billion boe is economic at year-end 2014.
Contingent resources are reported as the working interest volumes and Husky’s working interest in the properties. The properties assigned contingent resources are Western Canada gas resource plays and Enhanced Oil Recovery (“EOR”) projects, Lloydminster Heavy Oil projects, N.W.T. conventional gas, Oil Sands, Atlantic Region and Asia Pacific gas.
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. There is no certainty as to the timing of such development.
Specific contingencies preventing the classification of contingent resources in the Company’s Western Canada resource plays as reserves include required improvement in gas prices, optimization of drilling and completion design to further reduce costs, preparation of firm developments plans, timing of development and Company approvals. Positive and negative factors relevant to the estimate of Western Canada resource play resources include a higher level of uncertainty in the estimates as a result of a lower number of wells and limited production history.
Specific contingencies preventing the classification of contingent resources at the Company’s Lloydminster Heavy Oil discoveries as reserves include: it may not be viable to develop the estimated volumes in an economic manner; the formulation of concrete development plans to pursue development of the large inventory of primary and EOR opportunities; Company commitment to dedicate the required capital to develop the inventory of opportunities; large inventory of contingent resource opportunities would likely necessitate development over a time frame much greater than the five-year reserve timing window; regulatory submissions and approval would be required for the thermal and major EOR projects to proceed; and verification of sustained economic productivity using CHOPS from zones with limited tests to date and zones with higher viscosity as well as verification of sub-zone continuity and quality that would enable feasible implementation of an EOR scheme.
Positive and negative factors relevant to the estimation of Lloydminster Heavy Oil total heavy oil initially in place, discovered heavy oil initially in place and best estimate contingent resources include extensive well control, limited demonstrated sustained production in certain zones, potential reservoir heterogeneity in sub-zones which may limit the applicability of EOR schemes, and current lack of development plans.
The Company has disclosed total heavy oil initially in place in this news release. Total petroleum initially in place is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. There is no certainty that any portion of the undiscovered petroleum initially in place will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the undiscovered petroleum initially in place.
The Company has disclosed discovered heavy oil initially in place in this news release. Discovered petroleum initially-in-place is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered petroleum initially in place includes production, reserves, and contingent resources; the remainder is unrecoverable. There is no certainty that it will be commercially viable to produce any portion of the resources.
Specific contingencies preventing the classification of contingent resources at the Company’s Oil Sands properties as reserves include further reservoir studies, delineation drilling, facility design, preparation of firm development plans, regulatory applications and company approvals. Development is also contingent upon successful application of steam-assisted gravity drainage and/or Cyclic Steam Stimulation. Positive and negative factors relevant to the estimate of oil sands resources include a higher level of uncertainty in the estimates as a result of lower core-hole drilling density.
Specific contingencies preventing the classification of contingent resources at the Company’s Atlantic Region discoveries as reserves include additional exploration and 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.
Specific contingencies preventing the classification of contingent resources at the Company’s Asia Pacific Region discoveries as reserves include additional exploration and 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 Asia Pacific resources include water depth and distance from existing infrastructure.
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 “heavy oil initially in place” 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 directed.
For further information, please contact:
Manager, Investor Relations
Husky Energy Inc.
Manager, Media & Issues
Husky Energy Inc.