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 margin”, “EBITDA” and “operating netback”. Please refer to “Non-GAAP measures” at the end of this news release.
CALGARY, Alberta, July 25, 2019 (GLOBE NEWSWIRE) — Husky Energy (TSX:HSE) generated funds from operations of $802 million in the second quarter, with net earnings of $370 million. Cash flow from operating activities, including changes in non-cash working capital, was $760 million, compared to $1 billion in Q2 2018.
“We remain on track with the plan we outlined at our recent Investor Day,” said CEO Rob Peabody. “This includes the acceleration of the Lloyd thermal project at Dee Valley, which is now steaming with production expected later in the third quarter.
“Our focus remains on capital discipline and consistent execution, while increasing our ability to capture higher margins across the Integrated Corridor and Offshore businesses.”
Second quarter financial performance was impacted by lower production and reduced throughputs, primarily due to a heavy maintenance turnaround schedule and non-routine write offs and expenses. This maintenance program is now largely complete.
In the Downstream segment, the Lima crude oil flexibility project is on track for completion in the fourth quarter of 2019 and will provide increased heavy crude processing capacity. Construction is expected to begin on the Superior Refinery rebuild project this fall, subject to regulatory approvals.
In the Offshore business, Husky drilled the final three wells at the Liuhua 29-1 field at the Liwan Gas Project. All seven wells are expected to be completed by the end of 2019, with first production around the end of 2020. In the Atlantic region, two new infill wells were brought on production and construction advanced at the West White Rose Project.
The Company continues to deliver on the plan set out at Investor Day, including its 2019 guidance of $3.3 to $3.5 billion in capital expenditures and annual average production of 290,000-305,000 barrels of oil equivalent per day (boe/day).
SECOND QUARTER HIGHLIGHTS
- Net earnings of $370 million, including $233 million related to Alberta corporate tax reductions and non-routine after-tax negative adjustments totaling $77 million, compared to net earnings of $448 million in Q2 2018
- Cash flow from operating activities of $760 million, compared to $1 billion in the second quarter of 2018
- Funds from operations of $802 million, compared to $1.2 billion in the year-ago period. This reflects lower commodity prices, reduced production and throughputs due to turnarounds, and non-routine pre-tax negative adjustments totalling $106 million
- Capital spending of $858 million
- Net debt of $3.7 billion, representing one times trailing 12 months funds from operations
- Liquidity of approximately $6.7 billion; $2.5 billion in cash and $4.2 billion in unused credit facilities
- Upstream production averaged 268,400 boe/day, compared to 295,500 boe/day in Q2 2018, reflecting Alberta production quotas, lower volumes from the White Rose field and planned turnarounds at Sunrise and six Lloyd thermal projects
- Downstream throughput of 340,000 barrels per day (bbls/day), compared to 355,000 bbls/day in the year-ago period, with planned maintenance turnarounds at both the Toledo and Prince George refineries
- Lima Refinery throughput of 179,800 bbls/day, reflecting improvements made in the 2018 turnaround
|Three Months Ended||Six Months Ended|
|Upstream production, before royalties|
|Total equivalent production (mboe/day)||268||285||296||277||298|
|Crude oil and natural gas liquids (mbbls/day)||189||199||213||194||217|
|Natural gas (mmcf/day)||475||517||494||496||486|
|Upgrader and refinery throughput (mbbls/day)||340||334||355||337||376|
|Revenue, net of royalties ($mm)||5,303||4,574||5,884||9,877||11,066|
|Operating margin1 ($mm)||942||1,172||1,392||2,114||2,496|
|Cash flow – operating activities ($mm)||760||545||1,009||1,305||1,538|
|Funds from operations1 ($mm)
Per common share – Basic ($/share)
|Capital expenditures ($mm)||858||812||708||1,670||1,345|
|Free cash flow1 ($mm)||(56)||147||500||91||758|
|Net earnings ($mm)
Per common share – Basic ($/share)
|Net debt1 ($ billions)||3.7||3.4||3.0||3.7||3.0|
|Net debt to trailing funds from operations1(times)||1.0||0.8||0.8||1.0||0.8|
|Dividend per common share ($/share)||0.125||0.125||0.075||0.250||0.150|
|1Non-GAAP measure; refer to advisory.|
SECOND QUARTER RESULTS
Upstream production averaged 268,400 boe/day, compared to 295,500 boe/day in the second quarter of 2018, which takes into account the impacts from Alberta production quotas, lower volumes from the White Rose field and planned maintenance and turnarounds.
Average realized pricing for Upstream production was $53.35 per boe compared to $49.74 per boe in the year-ago period. Realized pricing for oil and liquids averaged $60.13 per barrel compared to $53.83 per barrel in the year-ago period, and natural gas pricing averaged $6.19 per thousand cubic feet (mcf), compared to $6.53 per mcf in Q2 2018. Upstream operating costs of $15.83 per boe were 11% higher than the year-ago period, primarily due to Alberta production quotas, increased costs related to turnarounds, and lower production in Western Canada and the Offshore business. Upstream operating netbacks averaged $33.61 per boe compared to $31.31 per boe in the second quarter of 2018.
Upgrader and refinery throughput of 340,000 bbls/day reflected planned turnarounds at the Prince George and Toledo refineries and the continued suspension of operations at the Superior Refinery.
The average realized U.S. refining and marketing margin was $14.16 US per barrel of crude oil throughput, which reflects a favourable first-in, first-out (FIFO) pre-tax inventory valuation adjustment of $0.60 US per barrel. This compared to $16.66 US per barrel a year ago, which included a favourable FIFO pre-tax inventory valuation adjustment of $1.96 US per barrel.
The Upgrader realized margin was $12.38 per barrel compared to $30.69 per barrel in the year-ago period, reflecting tighter Canadian heavy oil differentials.
Net earnings in the Infrastructure and Marketing segment were a loss of $38 million compared to a gain of $154 million in Q2 2018, due to a non-routine $43 million after-tax provision associated with a lump-sum contract for the Saskatchewan Gathering System expansion, as well as tighter heavy oil location differentials.
Capital spending of $858 million was focused on thermal bitumen project development in Saskatchewan, Downstream margin capture initiatives including the Lima crude oil flexibility project, construction of the Liuhua 29-1 field at Liwan and advancing construction of the West White Rose Project.
- Upstream production averaged 214,000 boe/day compared to 230,500 boe/day in Q2 2018, which takes into account Alberta production quotas and turnarounds at six Lloyd thermal projects in Saskatchewan
- Steaming commenced at the 10,000 bbls/day Dee Valley Lloyd thermal project
- The Lima crude oil flexibility project is 85% complete
- The Superior Refinery rebuild is expected to begin this fall, subject to regulatory approvals; a return to full operations is expected in 2021. The rebuild costs are expected to be substantially covered by property damage insurance
Thermal bitumen production from Lloyd thermal projects, Tucker and Sunrise averaged about 120,000 bbls/day (Husky W.I.), compared to 123,200 bbls/day (Husky W.I.) in the second quarter of 2018. This takes into account mandatory government production quotas in Alberta and turnaround and maintenance work at six Lloyd thermal projects, which were synchronized to coincide with water supply infrastructure maintenance.
Production at Sunrise averaged 45,400 bbls/day (22,700 bbls/day Husky W.I.). At Tucker, production averaged 24,000 bbls/day.
In Saskatchewan, five new Lloyd thermal projects with a combined design capacity of 50,000 bbls/day are being advanced.
The Company continues to pace investments in its liquids-rich resource play business with an ongoing focus on lowering costs, optimizing production rates and reducing cycle times.
In the second quarter, four wells were completed at Kakwa in the Spirit River formation and a planned turnaround at the Rainbow Lake gas processing plant was successfully completed.
Total Downstream throughput was 340,000 bbls/day, compared to 355,000 bbls/day in the second quarter of 2018.
U.S. refinery throughput averaged 237,300 bbls/day, including 179,800 bbls/day at the Lima Refinery. The Toledo Refinery averaged 115,000 bbls/day (57,500 bbls/day Husky W.I.), reflecting impacts from the extended planned maintenance turnaround.
The operating margin for the U.S. refining segment was $224 million. Pre-tax insurance proceeds of $71 million, primarily for business interruption at the Superior Refinery, was accounted for in the $300 million of EBITDA recorded in the quarter.
The Lima crude oil flexibility project to increase heavy oil processing capacity to 40,000 bbls/day is 85% complete and on track for completion by the end of 2019.
Canadian throughput, including the Lloydminster Upgrader and asphalt refinery, averaged 103,000 bbls/day, which takes into account an extended planned turnaround at the Prince George Refinery.
The operating margin for the combined Upgrading and Canadian Refined Products segments was $62 million.
- Production averaged 54,400 boe/day, compared to 65,000 boe/day in the second quarter of 2018
- Final three wells drilled at the seven-well Liuhua 29-1 field development; pipeline laying under way
- West White Rose Project more than 40% complete
Natural gas sales from the two producing fields at Liwan averaged 330 million cubic feet per day (mmcf/day), with associated liquids averaging 14,200 bbls/day (162 mmcf/day and 7,100 bbls/day Husky W.I.)
Realized gas pricing at Liwan was $14.05 per mcf, with liquids pricing of $69.77 per barrel. Operating costs were $5.25 per boe, with an operating netback of $71.66 per boe.
At the Liuhua 29-1 field, the final three wells were drilled and pipeline laying is expected to be finished in the third quarter. Altogether, seven wells will be tied in to existing Liwan infrastructure, with first gas expected around the end of 2020. Target production is 45 mmcf/day of gas and 1,800 bbls/day of liquids when fully ramped up, reflecting Husky’s 75% working interest.
Natural gas sales at the BD Project in the Madura Strait averaged 87 mmcf/day, with liquids production of 6,500 bbls/day (34 mmcf/day and 2,500 bbls/day, Husky W.I.) Realized gas pricing at BD was $9.94 per mcf, with liquids pricing of $101.07 per barrel. Operating costs were $9.52 per boe, with an operating netback of $53.77 per boe.
First gas production from the combined MDA-MBH and MDK fields in the Madura Strait is expected in 2021.
Overall average net production in the Atlantic region was approximately 12,200 bbls/day, which included two new infill production wells that were brought onstream in May 2019.
The Central Drill Centre and the Southern Drill Centre have resumed normal operations. With the installation earlier this month of a new subsea flowline connector, the drill centres at North Amethyst and the South White Rose extension are expected to be brought back into service in the third quarter of 2019.
The Tiger’s Eye exploration well did not encounter commercial hydrocarbons and was written off. Husky has a 40 percent ownership interest in the well.
West White Rose Project
Construction work on the concrete gravity structure and related topsides is progressing, with the overall project more than 40% complete as it advances towards first oil around the end of 2022.
A strategic review continues of the potential sale of the Canadian retail and commercial fuels business and the Prince George Refinery.
The Board of Directors has approved a quarterly dividend of $0.125 per common share for the three-month period ended June 30, 2019. The dividend will be payable October 1, 2019 to shareholders of record at the close of business on September 3, 2019.
Regular dividend payments on each of the Cumulative Redeemable Preferred Shares – Series 1, Series 2, Series 3, Series 5 and Series 7 – will be paid for the three-month period ended September 30, 2019. The dividends will be payable on September 30, 2019 to holders of record at the close of business on September 3, 2019.
|Share Series||Dividend Type||Rate (%)||Dividend Paid ($/share)|