This news release contains references to the non-GAAP financial measures “funds from operations”, “free cash flow”, “net debt”, “net debt to trailing funds from operations”, “operating netback” and “EBITDA”. Please refer to “Non-GAAP Measures” at the end of this news release.
CALGARY, Alberta, April 26, 2019 (GLOBE NEWSWIRE) — Husky Energy (TSX: HSE) generated funds from operations of $959 million in the first quarter of 2019, compared to $895 million in the first quarter of 2018. Net earnings were $328 million, compared to $248 million in Q1 2018 and free cash flow was $147 million, compared to $258 million in the first quarter of 2018. Cash flow from operating activities, which includes changes in non-cash working capital, was $545 million, compared to $529 million in Q1 2018.
“We delivered more funds from operations compared to the first quarter of 2018, despite Alberta government quotas on our oil production, and even with global oil prices pretty much on par in Canadian dollar terms,” said CEO Rob Peabody.
“The structural transformation of our business over the past several years is paying off. We are now realizing higher per-barrel margins across the Company.”
Peabody noted that while Husky’s Upstream segment made a strong contribution to funds from operations as a result of tighter Canadian heavy-light differentials, the largest benefit was from U.S. refining margins. “This further demonstrates the value of our Integrated Corridor business,” he said. “We can capture value at any point along the Upstream-Downstream chain, resulting in global pricing for most of our production.”
Husky further advanced its process safety and asset integrity program in the first quarter with the appointment of Peter Rosenthal as Senior Vice President of Safety and Operations Integrity, reporting directly to the CEO.
FIRST QUARTER HIGHLIGHTS
- Funds from operations of $959 million, up 64% over the previous quarter and 7% higher than Q1 2018
- Cash flow from operating activities of $545 million, compared to $529 million in Q1 2018; the quarter saw an increase in working capital driven by commodity prices, a seasonal increase in inventories and business interruption insurance accruals related to the Superior Refinery
- Net earnings of $328 million, up 52% over the previous quarter and 32% higher than Q1 2018
- Capital spending of $812 million, primarily directed to advancing Lloyd thermal bitumen projects and construction of the West White Rose Project; 2019 capital guidance remains on track
- Free cash flow of $147 million, compared to $258 million in Q1 2018
- Quarterly cash dividend of $0.125 per common share declared
- Net debt of $3.4 billion, representing 0.8 times trailing 12 months funds from operations; senior unsecured notes offering raised $750 million US for general corporate purposes, which may include repaying debt maturing in 2019
- Upstream production of 285,200 barrels of oil equivalent per day (boe/day) compared to 304,300 boe/day in Q4 2018, largely reflecting the impact of mandatory Alberta production quotas and limited production from the White Rose field; 2019 production guidance remains on track
- Downstream throughput of 333,600 barrels per day (bbls/day); including record throughput at the Lima Refinery as a result of efficiencies and optimizations
- Announced plans for the strategic review and potential sale of non-core Downstream assets, including the Company’s Canadian retail and commercial fuels business and the Prince George Refinery
- 10,000 bbls/day Dee Valley Lloyd thermal project progressing ahead of schedule, with first oil expected in Q4 2019
- Spruce Lake Central and Spruce Lake North Lloyd thermal projects, representing an aggregate of 20,000 bbls/day, are advancing towards first production in 2020
- Production at the White Rose field offshore Newfoundland and Labrador continues to ramp up following a temporary suspension of operations in the fourth quarter of 2018
- Two additional infill wells at the White Rose field are in the process of being tied in and are expected to be placed onto production in the coming days
- Continued strong Asia Pacific operating netbacks of $68.33 per boe
|Three Months Ended|
|Daily production, before royalties|
|Total equivalent production (mboe/day)||285||304||300|
|Crude oil and natural gas liquids (mbbls/day)||199||215||221|
|Natural gas (mmcf/day)||517||538||477|
|Upstream operating netback1,2 ($/boe)||27.69||9.42||24.37|
|Refinery and Upgrader throughput (mbbls/day)||334||287||398|
|Cash flow – operating activities ($mm)||545||1,313||529|
|Funds from operations1 ($mm)||959||583||895|
|Per common share – Basic ($/share)||0.95||0.58||0.89|
|Free cash flow1 ($mm)||147||(682)||258|
|Net earnings ($mm)||328||216||248|
|Per common share – Basic ($/share)||0.32||0.21||0.24|
|Net debt3 ($ billions)||3.4||2.9||3.2|
|Dividend per common share ($/share)||0.125||0.125||0.075|
|1Non-GAAP measure; refer to advisory.
2Operating netback includes results from Upstream Exploration and Production and excludes Upstream Infrastructure and Marketing.
3Net debt is a non-GAAP measure that equals the sum of long-term debt, long-term debt due within one year and short-term debt, less cash and cash equivalents. Refer to advisory.
FIRST QUARTER RESULTS
Upstream production averaged 285,200 boe/day, compared to 300,400 boe/day in the first quarter of 2018. This takes into account mandated Alberta government production quotas and the ongoing ramp-up of operations at the White Rose field, which resumed production at the end of January 2019. Production in the Atlantic region averaged 7,600 bbls/day in the quarter compared to 28,400 bbls/day a year ago.
Upstream operating netbacks averaged $27.69 per boe, compared to $24.37 per boe in the first quarter of 2018, reflecting tighter Canadian heavy oil differentials. Average realized pricing for Upstream production was $47.20 per boe, compared to $40.87 per boe in the year-ago period. Realized pricing for oil and liquids averaged $49.14 per barrel, and natural gas averaged $7.12 per thousand cubic feet (mcf).
Upstream operating costs averaged $16.30 per boe, compared to $13.33 per boe in the first quarter of 2018. The increase was due to a combination of factors, including Alberta production quotas, reduced Atlantic volumes as the White Rose field continues its production ramp up, and higher gas and electricity costs in Western Canada.
Total Downstream throughput was 333,600 bbls/day compared to 398,100 bbls/day in Q1 2018, which takes into account the continued suspension of operations at the Superior Refinery.
The Chicago 3:2:1 crack spread averaged $13.08 US per barrel compared to $12.84 US per barrel in Q1 2018.
The average realized U.S. Refining and Marketing margin was $17.64 US per barrel of crude throughput, which reflects a favourable first-in, first-out (FIFO) pre-tax inventory valuation adjustment of $3.91 US per barrel. This compared to $8.51 US per barrel a year ago, which included a favourable FIFO pre-tax inventory valuation adjustment of $0.28 US per barrel.
The Upgrading realized margin was $21.24 per barrel, down from $31.63 per barrel in the year-ago period, largely due to tighter heavy oil differentials.
In the Infrastructure and Marketing segment, EBITDA was $171 million compared to an EBITDA of $190 million in Q1 2018, primarily reflecting the value captured from the Company’s long-term committed oil and gas export pipeline capacity and storage assets.
Funds from operations were $959 million, compared to $895 million in the first quarter of 2018. Capital expenditures were $812 million, leading to free cash flow of $147 million. Net earnings were $328 million.
Capital spending included investments in Lloyd thermal projects, the West White Rose Project, the Liuhua 29-1 field development, and the crude oil flexibility project at the Lima Refinery.
- Upstream average production of 231,500 boe/day
- Overall upstream operating netback of $21.03 per boe, compared to $10.91 per boe in Q1 2018
- $30.89 per barrel netback from thermal operations
- Downstream throughput of 333,600 bbls/day
- Downstream upgrading/refining margin of $22.81 per barrel
- Infrastructure and Marketing realized margin of $167 million
The government production quota for Husky in Alberta averaged out to be 86,000 bbls/day in the first quarter, which resulted in the shut-in of approximately 20,000 bbls/day of production. Impacts included:
- Production at the Sunrise Energy Project averaged 44,600 bbls/day (22,300 bbls/day Husky working interest) compared to 54,400 bbls/day (27,200 bbls/day Husky working interest) in the fourth quarter of 2018 and 59,000 bbls/day in December 2018 (29,500 bbls/day Husky working interest).
- At Tucker, production averaged 25,000 bbls/day compared to 25,200 bbls/day in the fourth quarter of 2018 and 27,500 bbls/day in December 2018.
Total thermal bitumen production from Lloyd thermal projects, Tucker and Sunrise averaged about 130,300 bbls/day (Husky working interest), compared to 123,200 bbls/day (Husky working interest) in the first quarter of 2018. Overall operating costs at Sunrise, Tucker and 10 producing Lloyd thermal projects were approximately $13.79 per barrel. Costs were up due to higher gas and electricity prices as well as the impacts from the production quota.
Five 10,000 bbls/day Lloyd thermal projects are being advanced through 2022, with a combined design capacity of 50,000 bbls/day. These long-life thermal projects are being phased to optimize capital efficiency and project execution.
- At Dee Valley, first oil is expected in the fourth quarter of 2019
- At Spruce Lake Central, the central processing facility is under construction with first production anticipated in the second half of 2020
- At Spruce Lake North, first oil is planned around the end of 2020
- At Spruce Lake East, first production is expected around the end of 2021
- At Edam Central, first production is anticipated in 2022
The Pikes Peak Lloyd thermal project was shut in in February 2019 and will now be abandoned, after producing 78 million barrels over 36 years of operations.
In the Ansell and Kakwa areas, eight wells were drilled and six completed, with drilling focusing on liquids rich wells in the Cardium and Spirit River formations. In the liquids-rich Montney formation, three wells were drilled at Wembley and one at Sinclair.
Canadian throughput, including the Lloydminster Upgrader and asphalt refinery, averaged 104,200 bbls/day. EBITDA was $157 million.
U.S. refining throughput averaged 229,400 bbls/day, with record refining throughputs at the Lima Refinery following a turnaround in Q4. Throughput at the Lima Refinery averaged 171,400 bbls/day compared to 164,400 bbls/day in the first quarter of 2018. The crude oil flexibility project to increase heavy oil processing capacity from 10,000 bbls/day to 40,000 bbls/day is on pace for the end of 2019.
The U.S. refining segment recorded EBITDA of $341 million, which included $113 million in pre-tax insurance proceeds primarily for business interruption at the Superior Refinery. The refinery rebuilding project is expected to begin this fall, subject to regulatory approvals, with partial operations targeted for late 2020.
- Average production of 53,700 boe/day
- Operating netback of $56.28 per boe
- China operating netback of $72.95 per boe
- Indonesia operating netback of $48.05 per boe
Sales gas production from the two producing fields at the Liwan Gas Project averaged 369 million cubic feet per day (mmcf/day), with associated liquids averaging 15,600 bbls/day (181 mmcf/day and 7,700 bbls/day Husky working interest). Realized gas pricing was $14.35 Cdn per mcf, with liquids pricing of $69.11 Cdn per barrel.
At the Liuhua 29-1 field, drilling of three remaining wells is expected to be completed in the second quarter of 2019. Altogether, seven wells will be tied into the existing Liwan infrastructure, with first gas expected around the end of 2020. Target production from this third deepwater field at Liwan is 45 mmcf/day of gas and 1,800 bbls/day of liquids when fully ramped up, reflecting Husky’s 75% working interest.
Sales gas production at the liquids-rich BD Project averaged 89 mmcf/day, with liquids production of 5,700 bbls/day (34 mmcf/day and 2,600 bbls/day Husky working interest), reflecting a planned 12-day maintenance completed in the first quarter.
BD production was sold at contracted rates for a realized gas price of $9.88 Cdn per mcf, with liquids pricing of $81.96 Cdn per barrel.
Overall average net production was approximately 7,600 bbls/day. This compares to 28,400 bbls/day in the same period a year ago and reflects the suspension of operations at the White Rose field in November 2018.
White Rose Field Update
Operations resumed at the end of January from the Central Drill Centre at the White Rose field, with production expected to continue ramping up through the second quarter as additional subsea drill centres are brought on stream. Current production from the White Rose field is approximately 5,000 bbls/day, Husky working interest.
Two additional infill wells at the White Rose field are in the process of being tied in and are expected to be placed onto production in the coming days.
West White Rose Project
Construction work on the drilling and wellhead platform, topsides and living quarters continues to progress, with first oil anticipated in 2022.
Husky announced the appointment of a new Senior Vice President of Safety and Operations Integrity. Peter Rosenthal reports directly to the CEO and will oversee process and occupational safety, operations integrity and emergency response. He has deep experience in process safety and risk management, with nearly 30 years of industry experience.
During the quarter, Husky raised $750 million US in a senior unsecured notes offering with the proceeds being used for general corporate purposes, which may include, among other things, the repayment of certain outstanding debt securities maturing in 2019.
The Board of Directors has approved a quarterly dividend of $0.125 per common share for the three-month period ended March 31, 2019. The dividend will be payable July 2, 2019 to shareholders of record at the close of business on June 10, 2019.
Regular dividend payments on each of the Cumulative Redeemable Preferred Shares – Series 1, Series 2, Series 3, Series 5 and Series 7 – will be paid for the three-month period ended June 30, 2019. The dividends will be payable on July 2, 2019 to holders of record at the close of business on June 10, 2019.
|Share Series||Dividend Type||Rate (%)||Dividend Paid ($/share)|
A conference call will be held on Friday, April 26 at 8 a.m. Mountain Time (10 a.m. Eastern Time) to discuss Husky’s 2019 first quarter results. CEO Rob Peabody, COO Rob Symonds and CFO Jeff Hart will participate in the call.
|To listen live:
Canada and U.S. Toll Free: 1-800-319-4610
|To listen to a recording (after 9 a.m. MT on April 26):
Canada and U.S. Toll Free: 1-800-319-6413
Following the conference call, the Company will hold its Annual Meeting of Shareholders at 10:30 a.m. (Mountain Time) in the Performance Hall at Studio Bell, 850 4th Street S.E., Calgary, Alberta.
A live webcast of the meeting will be available at www.huskyenergy.com under Investor Relations. The archived webcasts of the conference call and the meeting will be available for approximately 90 days.