CALGARY, AB–(Marketwired – May 06, 2015) – Husky Energy (TSX: HSE) reported solid results in the first quarter, including cash flow from operations of $838 million, net earnings of $191 million and production of 356,000 barrels of oil equivalent per day (boe/day), reflecting the resiliency of its portfolio in a low oil price environment.
“The structural changes made by Husky since 2010, including the decision to remain an integrated and diversified company, will continue to yield benefits beyond the current commodity price cycle,” said CEO Asim Ghosh.
“The balanced growth strategy we set out five years ago repositioned our portfolio towards longer-life projects with low sustaining costs,” added Ghosh. “We have since moved the needle considerably, with total production from low sustaining capital projects expected to grow to over 40 percent by the end of 2016 from just eight percent five years ago. As a result, we will require less capital to sustain a larger base of our production.”
In addition, progress is being made to lower Husky’s overall costs through efficiencies.
- A cost reduction program initiated five years ago by the Company has achieved more than $1.3 billion in cumulative supply and procurement savings. A further $400-600 million in cost savings was targeted for 2015, of which $475 million has been locked in to date.
- Operating costs per barrel decreased more than 13 percent to $14.87 per barrel in the first quarter compared to $17.21 per barrel in the same period a year ago. This primarily reflects lower cost production coming onstream as well as lower energy input costs.
Creating Value Through the Cycle
Husky delivered another significant milestone in March with production starting at the Sunrise Energy Project in northern Alberta. Sunrise is expected to steadily ramp up to full capacity of about 60,000 barrels per day (30,000 bbls/day net to Husky) around the end of 2016.
Capacity at the planned Edam West heavy oil thermal project has been increased from 3,500 bbls/day to 4,500 bbls/day through design and efficiency improvements, and the project is on track for startup in the fourth quarter of 2016.
The Company remains on track to add approximately 85,000 bbls/day of net new production by the end of 2016, a portion of which is expected to offset natural declines across the portfolio. The projects are expected to deliver positive returns despite a lower oil price environment.
|Projects in Development||Business||First Production||Forecast Net Peak Production (bbls/day)|
|Sunrise Energy Project Plant 1A||Oil Sands||Delivered||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||Increased to 4,500 from 3,500|
|Vawn||Heavy Oil Thermal||Q4/16||10,000|
FINANCIAL AND OPERATIONAL HIGHLIGHTS
Average production rose nine percent to 356,000 boe/day from 326,000 boe/day in the first quarter of 2014. This reflected steady production from the Liwan Gas Project, strong performance from heavy oil thermal developments and increased production from the Ansell liquids-rich gas resource play. Production is expected to decline in the second quarter due to a maintenance program on the partner-operated Terra Nova FPSO (floating production, storage and offloading) vessel, a three-week turnaround at the Tucker heavy oil thermal project, and other planned upstream maintenance and third-party turnarounds.
Cash flow from operations was $838 million, which takes into account positive Downstream results and strong performance from Liwan facilities, which have operated at 99 percent reliability in the first year.
Net earnings were $191 million, which includes recognition of $203 million in deferred tax recovery as a result of the partial payment of the contribution payable to BP-Husky Refining LLC. It also reflects lower realized crude oil prices and North American natural gas prices, along with lower U.S. refining and marketing margins resulting from a drop in market crack spreads.
As a result of its diverse portfolio, a portion of the Company’s earnings and cash flow are not directly exposed to current oil price challenges. This includes Liwan gas, which is sold at a fixed price, and the margin-based Downstream business.
Husky continues to maintain a strong balance sheet and financial flexibility through the current market cycle. The Company’s debt-to-capital employed ratio was about 22 percent at the end of March, with approximately $3.2 billion in undrawn committed term credit facilities.
The Company undertook several financing initiatives during the quarter to further strengthen its balance sheet, including a $750 million notes offering to refinance existing debt and a $200 million preferred shares issuance.
|Three Months Ended|
|1)||Daily Production, before royalties|
|Total Equivalent Production (mboe/day)||356||360||326|
|Crude Oil and NGLs (mbbls/day)||237||243||242|
|Natural Gas (mmcf/day)||717||702||506|
|2)||Operating Netback ($/boe) (1)(2)||21.45||34.84||44.81|
|3)||Refinery and Upgrader Throughput (mbbls/day)||296||344||289|
|4)||Cash Flow from Operations(2) (Cdn $ millions)||838||1,145||1,536|
|Per Common Share – Basic ($/share)||0.85||1.16||1.56|
|Per Common Share – Diluted ($/share)||0.85||1.16||1.56|
|5)||Net Earnings /Loss (Cdn $ millions)||191||(603)(3)||662|
|Per Common Share – Basic ($/share)||0.19||(0.62)||0.67|
|Per Common Share – Diluted ($/share)||0.17||(0.65)||0.66|
|6)||Capital Investment, including acquisitions (Cdn $ millions)||821||1,419||1,269|
|Per Common Share ($/share)||0.30||0.30||0.30|
(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 Q1 MD&A, Section 11, which is incorporated herein by reference.
(3) Includes one-time charges for asset impairments and a provision to reduce inventory to net realizable value.
Downstream throughputs were 296,000 bbls/day up from 289,000 bbls/day in the first quarter of 2014. This takes into account reduced capacity at the Lima Refinery since January and an outage at the partner-operated Toledo refinery in March.
West Texas Intermediate prices averaged $48.63 US per barrel in the first quarter compared to $98.68 US a year ago. Average realized pricing for the Company’s total Upstream production was $40.84 per barrel, compared to $72.21 in the first quarter of 2014.
U.S. refining Chicago market crack spreads averaged $16.14 US per barrel, compared to $18.35 US in the first quarter of 2014, while the realized U.S. refining margin averaged $10.04 US per barrel compared to $21.63 US a year ago.
KEY AREA SUMMARY
- Heavy Oil
The Company is advancing a strong lineup of heavy oil thermal projects. These long-life developments are being built with modular, repeatable designs and are expected to require low sustaining capital once brought online. Total heavy oil thermal production in the first quarter averaged 45,500 bbls/day, with operating costs of $9.53 per barrel.
The 3,500 bbls/day Sandall thermal project, which came online in early 2014, produced strong results above its nameplate design with average volumes of 5,600 bbls/day.
Construction was advanced on the 10,000 bbls/day Rush Lake thermal project, with first oil scheduled for the third quarter.
Work continued on three other thermal developments:
- The 10,000 bbls/day Edam East project is scheduled to come onstream in the third quarter of 2016.
- The 3,500 bbls/day Edam West thermal development has been reconfigured to a capacity of 4,500 bbls/day and is set to begin production in the fourth quarter of 2016.
- The 10,000 bbls/day Vawn project is expected to start up in the fourth quarter of 2016.
- Western Canada
Husky is targeting efficiencies across its expansive portfolio in Western Canada and has paced some of its projects.
The Ansell liquids-rich gas resource play remains a priority, with first quarter activity including drilling, completions and facility construction. Production volumes at Ansell in the first quarter averaged 19,300 boe/day compared to 17,000 boe/day in the first quarter of 2014.
The Company is progressing several other resource plays that offer good returns in a low price environment, with low finding and development costs. Production from the Strachan, Wapiti, Kakwa and Stolberg plays averaged about 8,000 boe/day in the first quarter.
Husky plans to advance these resource plays at a measured pace.
Husky’s Downstream business supported its Canadian land-based crude oil production in the first quarter through refining capability, improved infrastructure and increased storage capacity.
Expansion work on the Company’s Saskatchewan Gathering System is under way in preparation for increased heavy oil thermal production from a series of near-term planned projects.
Two new 300,000-barrel storage tanks and associated pipe infrastructure are now in service at Hardisty, Alberta, providing further flexibility to the business.
The Lima Refinery continues to operate at about 80 percent capacity. Work resumption plans are underway for the isocracker, which is expected to start up in the first quarter of 2016. The Company has insurance in place for property loss and business interruption in connection with the isocracker unit.
- Asia Pacific Region
Actual gas sales volumes from the Liwan Gas Project averaged 262 million cubic feet per day (mmcf/day, gross) in the first quarter. In accordance with the fixed price gas sales agreement, the Company and its partner received payment for 300 mmcf/day. Average gross sales volumes from Liwan, including Liuhua 34-2, are expected to increase to a range of 290-320 mmcf/day (gross) in 2015.
Husky will receive about 75 percent of gross production revenue until exploration costs are recovered, which is expected around the end of May 2015. The Company’s share of production will then revert to its equity interest of 49 percent.
Sales of natural gas liquids increased to an average of 13,600 boe/day from 11,300 boe/day (gross) in the fourth quarter of 2014.
Construction of a wellhead platform and pipeline infrastructure was advanced at the liquids-rich BD gas field in the Madura Strait. An FPSO has been contracted and is being built to process the gas and liquids production from the field, with first production anticipated in 2017.
- Oil Sands
First production commenced at the Sunrise Energy Project in mid-March. Steaming is underway on 34 of 55 well pairs, with strong facility performance.
Production is being ramped up gradually to achieve optimum results. Volumes are currently averaging 2,500-3,000 bbls/day (gross) and steadily building. Systems have been filled and shipping is under way.
The Company continues to realize a number of efficiencies associated with current operations:
- A new custom mobile drilling rig spudded its initial well in the first quarter, and has already demonstrated improved drilling efficiencies.
- The rig also provides for closer spacing of wellheads, smaller drilling pads and fewer pad facilities. This, along with the incorporation of new technologies such as multi-phase metering, will result in well cost savings of about 30 percent compared to the initial pads.
- The rig’s efficiency has provided the opportunity to advance the drilling schedule for sustaining pads, which are in the vicinity of initial production wells. Drilling the sustaining wells prior to steaming the initial production wells protects the steam chamber, is more efficient and safeguards well integrity. Production from the sustaining wells is not expected to be required for several years.
- The new sustaining pad design is expected to reduce land disturbance by about 30 percent.
Additional efficiencies are being realized in relation to commissioning work on the second processing plant:
- Electrical and pipe activities are being conducted concurrently, resulting in a more streamlined construction schedule.
- Improved project coordination has better integrated the construction and commissioning phases, leading to further efficiencies.
The second plant is on schedule. Production is expected to ramp up steadily towards full capacity of about 60,000 barrels per day (30,000 bbls/day net to Husky) around the end of 2016.
- Atlantic Region
Drilling and completion operations continued at the South White Rose extension project in the Jeanne d’Arc Basin, with first oil anticipated by mid-2015. Production from the field will be tied back to the SeaRose FPSO through a series of flexible underwater flowlines, with net peak production expected to reach 15,000 bbls/day once the development is fully ramped up.
Drilling is planned to resume at a Hibernia-level formation well beneath the North Amethyst field after the first two South White Rose production wells have been brought online in mid-year. The well is expected to begin production in the third quarter, with forecast net peak production of 5,000 bbls/day.
This new Atlantic Region production is expected to stabilize Husky’s overall production levels for the balance of 2015, with production from South White Rose and the North Amethyst Hibernia-level well offsetting the impact of natural declines from the White Rose and Terra Nova fields.
Husky continues to advance its assessment of both the subsea and wellhead platform concepts in relation to the development of the West White Rose field.
An exploration and appraisal program is progressing as planned in the Bay du Nord discovery area in the Flemish Pass.
MAINTENANCE AND TURNAROUND PLANS
Production declines are expected due to the following maintenance programs:
- A three-week shutdown is scheduled at the Tucker heavy oil thermal project, with an estimated impact of about 7,300 bbls/day over the month of May.
- A planned turnaround on the partner-operated Terra Nova FPSO starting in May is expected to last 10 weeks, with an estimated impact of about 8,000 bbls/day to Husky during the shutdown.
- Scheduled maintenance at the Ansell liquids-rich gas resource play is expected to reduce production by about 1,700 boe/day in the second quarter.
- Partial shutdowns are planned at several heavy oil thermal projects in June to perform routine maintenance, with an estimated aggregate impact of 8,000 bbls/day in June.
- Third-party turnarounds and outages in Western Canada are anticipated to continue in the second quarter.
- A turnaround at the Ram River plant in Western Canada previously scheduled for the second quarter has been deferred to 2016.
- An 18-day turnaround on the SeaRose FPSO vessel is set for the third quarter of 2015.
- The Lima Refinery is currently operating at about 80 percent capacity. Work resumption plans are underway for the isocracker, which is expected to start up in the first quarter of 2016.
- A planned turnaround at the partner-operated refinery in Toledo in the third quarter has been deferred to 2016.
In mid-April, the Company announced the appointment of Jon McKenzie as Chief Financial Officer. The appointment was effective as of April 27, 2015.
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 March 31, 2015. The dividend will be payable on July 2, 2015 to shareholders of record at the close of business on June 5, 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 April 1, 2015 to June 30, 2015. The dividend of $0.27813 per Series 1 Preferred Share will be payable on June 30, 2015 to holders of record at the close of business on June 5, 2015.
A regular 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 April 1, 2015 to June 30, 2015. The dividend of $0.28125 per Series 3 Preferred Share will be payable on June 30, 2015 to holders of record at the close of business on June 5, 2015.
The initial quarterly dividend payment on the 4.50 percent Cumulative Redeemable Preferred Shares, Series 5 (the “Series 5 Preferred Shares”) will be paid for the period March 12, 2015 to June 30, 2015. The dividend of $0.3390 per Series 5 Preferred Share will be payable on June 30, 2015 to holders of record at the close of business on June 5, 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 May 28, 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 Wednesday, May 6 at 8 a.m. Mountain Time (10 a.m. Eastern Time) to discuss Husky’s first 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 Jon McKenzie, Deputy CFO and Treasurer Darren Andruko and Downstream Senior VP Bob Baird will participate in the call. To listen to a recording of the call, available at 10 a.m. Mountain Time on May 6, 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 June 7, 2015
Following the call, the Company will hold its Annual and Special Meeting of Shareholders at 10:30 a.m. (Mountain Time) in the Palomino Room at the BMO Centre, Stampede Park in Calgary, Alberta.
A live webcast of the meeting will be available at www.huskyenergy.com under Investor Relations. The archived webcast of the meeting will be available for approximately 90 days.
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.C and HSE.PR.E. 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 general strategic plans and growth strategies; expected growth of total production, including production from low sustaining capital projects, by the end of 2016; anticipated reduction in capital required to sustain the Company’s production; target cost savings for 2015; anticipated volume of net new production additions by the end of 2016 and expected ability of this production to offset natural declines; expected ability of the Company’s projects in development to deliver positive returns; expected decline in production during the second quarter due to planned maintenance and turnaround programs at the Company’s projects; expected ability of new production from the Atlantic Region to stabilize the Company’s overall production levels for the remainder of the year; and planned timing, duration and impact of maintenance and turnaround programs at the Company’s projects;
- with respect to the Company’s Asia Pacific Region: expected timing of recovery of exploration costs by the Company at the Liwan Gas Project; expected increase in range of average gross sales volumes from Liwan; and anticipated timing of first production from the Madura Strait BD gas field;
- 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 and North Amethyst Hibernia well projects; anticipated timing of resumption of drilling at the North Amethyst Hibernia well;
- with respect to the Company’s Oil Sands properties: expected timing of ramp-up to full production capacity at the Sunrise Energy Project; anticipated timing of first production at Sunrise Energy Project Plant 1B; timing and volume of forecast net peak production from Sunrise Energy Project Plant 1A and 1B; anticipated timing of a requirement for sustaining pad production at the Company’s Sunrise Energy Project; expected well cost savings as a result of drilling efficiencies and the incorporation of new technologies; and expected effect of new pad design on land disturbance;
- with respect to the Company’s Heavy Oil properties: planned capacity, and timing of startup, at the Edam West thermal project; anticipated timing of first production, and forecast net peak daily production, from the Company’s Rush Lake, Edam East, Edam West and Vawn heavy oil thermal projects; expected requirement for low sustaining capital by the Company’s heavy oil thermal projects; and scheduled timing of first oil at the Rush Lake project;
- with respect to the Company’s Western Canadian oil and gas resource plays: ability of the Company’s resource plays to offer good returns and low finding and development costs and the Company’s strategy to advance these resource plays; and
- with respect to the Company’s Downstream operating segment: expected timing of start up at the Lima Refinery isocracker.
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, 2014 and other documents filed with securities regulatory authorities (accessible through the SEDAR website www.sedar.com and the EDGAR website www.sec.gov) describe risks, material assumptions and other factors that could influence actual results and are incorporated herein by reference.
Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by applicable securities laws, the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company’s course of action would depend upon its assessment of the future considering all information then available.
Disclosure of Oil and Gas Information
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.
Note to U.S. Readers
All currency is expressed in Canadian dollars unless otherwise directed.
Manager, Investor Relations
Husky Energy Inc.
Manager, Media & Issues
Husky Energy Inc.