Husky Energy reports 2019 fourth quarter and annual results
Husky Energy has reported its results for the fourth quarter and full year of 2019. The company states it generated funds from operations of $3.3 billion in 2019, including $469 million in the fourth quarter. Cash flow from operating activities, including changes in non-cash working capital, was $3 billion in 2019, including $866 million in the fourth quarter.
Fourth quarter operating results were negatively impacted by several factors, including:
- Lower U.S. crack spreads and an extended shutdown of the Lima Refinery to complete the crude oil flexibility project
- Lower Infrastructure and Marketing margins compared to Q4 2018, primarily due to narrower location differentials, and an outage on the Keystone pipeline in November, which impacted Husky's ability to capture the differential
- Severance costs related to staff reductions
"We delivered on critical milestones during the year, including our top priority of improved safety performance," said CEO Rob Peabody. "We met our production and capital guidance, achieved first oil at the 10,000 barrel-per-day Dee Valley thermal bitumen project and have completed the safe startup of the Lima Refinery crude oil flexibility project."
In the fourth quarter, Husky recognized asset impairment and other charges of $2.3 billion (after tax), largely related to long-term price assumptions and reductions in the Company's long-term capital expenditure plans.
The Board of Directors has approved a quarterly dividend of $0.125 per common share for the three-month period ended December 31, 2019. The dividend will be payable on April 1, 2020 to shareholders of record at the close of business on March 17, 2020.
- No major safety incidents, more than 50% reduction in lost-time injuries and Tier 1 process safety events
- Production within guidance at 290,000 barrels of oil equivalent per day (boe/day)
- Capital expenditures within guidance at $3.4 billion, including the Superior Refinery rebuild capital
- Project execution included the startup of the 10,000 barrel-per-day Dee Valley thermal bitumen project ahead of schedule, the completion of the Lima Refinery crude oil flexibility project and the sale of the Prince George Refinery
- Annual average production from Lloydminster thermal bitumen projects, Sunrise and Tucker of 128,800 barrels per day (bbls/day), Husky working interest (W.I.), compared to annual average production of 124,200 bbls/day in 2018 (Husky W.I.); takes into account impacts of the government-mandated production quotas in Alberta
- Average gross natural gas and liquids production at the Liwan Gas Project of 73,200 boe/day (35,900 boe/day Husky W.I.)
- Completed fourth quadrant of the concrete gravity base at the West White Rose Project ahead of schedule; project now 57% complete with first oil planned for around the end of 2022
- Dividends declared during the year totalled $0.50 per common share. In 2019, the Company returned $503 million in cash payments to shareholders, up from $276 million in 2018
FOURTH QUARTER RESULTS
- Funds from operations of $469 million, compared to $583 million in the year-ago period; reflects lower U.S. crack spreads, the extended shutdown at the Lima Refinery, lower Infrastructure and Marketing margins and $74 million related to employee severance. The operating margin at the Lima Refinery was negative $129 million, reflecting impacts from the shutdown to complete the crude oil flexibility project
- Cash flow from operating activities, including changes in non-cash working capital, of $866 million, compared to $1.3 billion in the fourth quarter of 2018
- Net loss of $2.3 billion, compared to net earnings of $216 million in Q4 2018, reflecting fourth quarter after-tax impairments. Net earnings excluding impairments, write-downs and the asset de-recognition were $5 million
- Capital spending of $894 million, including Superior Refinery rebuild capital; primarily directed towards advancing the growing Saskatchewan thermal portfolio and progressing construction of the Liuhua 29-1 field offshore China and the West White Rose Project in the Atlantic region
- Net debt of $3.7 billion, including proceeds from the sale of the Prince George Refinery; total liquidity (cash and unused credit facilities) of $5.7 billion
- Overall Upstream production of 311,300 boe/day, compared to 304,300 boe/day in Q4 2018; takes into account ongoing mandated production quotas in Alberta
- Downstream throughput of 203,400 bbls/day, compared to 286,900 bbls/day in Q4 2018; reflects the extended shutdown of the Lima Refinery
FOURTH QUARTER IMPAIRMENTS & OTHER IMPACTS
Total non-cash asset impairments and other charges were $2.3 billion (after tax) in the fourth quarter of 2019. These were primarily related to the Company's upstream assets in North America, including the Sunrise Energy Project and the Atlantic and Western Canada segments, and were largely due to lower long-term commodity price assumptions and a reduction in future capital spending. The reduction in future capital spending has the effect of reducing reserves, which in turn reduces asset values. Other charges included exploration-related write-downs and asset de-recognition at the Lima Refinery associated with redundant equipment following the completion of the crude oil flexibility project.
Average realized pricing for Upstream production was $46.06 per boe compared to $25.47 per boe in the same period in 2018. Realized pricing for oil and liquids averaged $47.52 per barrel compared to $18.93 per barrel in Q4 2018, and natural gas pricing averaged $7.02 per thousand cubic feet (mcf), compared to $6.86 per mcf in the year-ago period.
Upstream operating costs were $15.25 per boe compared to $13.75 per boe in Q4 2018, primarily due to higher energy and transportation costs, and lower production.
Upstream operating netbacks averaged $27.48 per boe compared to $9.42 per boe in the year-ago period.
Upgrader and refinery throughput was 203,400 bbls/day, compared to 286,900 bbls/day in the same period in 2018. This takes into account an extended turnaround at the Lima Refinery to complete the crude oil flexibility project.
The Chicago 3:2:1 crack spread averaged $12.06 US per barrel compared to $13.38 US per barrel in Q4 2018. The average realized U.S. refining and marketing margin was $7.85 US per barrel of crude oil throughput, which reflects an unfavourable first-in, first-out (FIFO) pre-tax inventory valuation adjustment of $0.24 US per barrel. This compared to $9.12 US per barrel a year ago, which included an unfavourable FIFO pre-tax inventory valuation adjustment of $8.51 US per barrel.
The Upgrader realized margin was $20.21 per barrel compared to $29.13 per barrel in the same period in 2018, which takes into account narrower light-heavy differentials.
The operating margin in the Infrastructure and Marketing segment was $12 million compared to $175 million in Q4 2018, largely due to narrower location differentials and the outage in November on the Keystone pipeline.
Q4 INTEGRATED CORRIDOR
- Average Upstream production of 241,600 boe/day, compared to 240,100 boe/day in Q4 2018
- Operating margin of $293 million, compared to $334 million in the fourth quarter of 2018
- Downstream throughput of 203,400 bbls/day, compared to 286,900 bbls/day in Q4 2018
Combined average thermal bitumen production from Lloydminster thermal projects, the Tucker Thermal Project and the Sunrise Energy Project was 137,800 bbls/day (Husky W.I.), which takes into account extended production quotas in Alberta, compared to 132,900 bbls/day (Husky W.I.) in Q4 2018. Overall production from the Lloyd thermal portfolio averaged 88,300 bbls/day compared to 80,500 bbls/day in the year-ago period, with an average of 92,000 bbls/day in December.
Five new Saskatchewan thermal bitumen projects with a combined nameplate capacity of 50,000 bbls/day are being advanced through 2023. The Spruce Lake Central project is 92% complete, with startup expected by mid-year 2020. The Spruce Lake North project is 60% complete, with first oil planned around the end of 2020.
Downstream U.S. refinery throughput averaged 91,700 bbls/day, compared to 179,100 bbls/day in the year-ago period.
The Lima Refinery average throughput was 21,400 bbls/day, which takes into account an extended shutdown to complete the crude oil flexibility project. This, along with lower crack spreads, contributed to an overall negative operating margin of $169 million for the U.S. refining segment, compared to an operating margin of $45 million in the year-ago period.
The Superior Refinery rebuild is under way with a return to full operations expected in 2021. Rebuild costs are expected to be substantially covered by property damage insurance. Pre-tax business interruption insurance recovery in the fourth quarter was $116 million. Insurance recovery related to the rebuild (not included in funds from operations) was $194 million.
Canadian throughput, including the Upgrader, Asphalt Refinery and Prince George Refinery, averaged 111,700 bbls/day. A project to increase diesel production at the Upgrader from 6,000 bbls/day to nearly 10,000 bbls/day is expected to be completed in the second quarter. The Upgrader captured margins of $20.21 per barrel.
The operating margin for the combined Upgrading and Canadian Refined Products segments was $126 million. The overall Downstream operating margin was negative $43 million, compared to a positive operating margin of $296 million in Q4 2018.
A strategic review of the potential sale of the Canadian retail and commercial fuels business continues to progress.
The Company continues to pace investment in its liquids-rich resource play business in Western Canada with an ongoing focus on lowering costs, optimizing production rates and reducing cycle times while supplying natural gas to its thermal operations. In the Montney Formation, six liquids-rich wells at Wembley were started up in the fourth quarter.
- Average production of 69,700 boe/day, compared to 64,200 boe/day in the fourth quarter of 2018
- Operating netback of $61.00 per boe
- Asia Pacific operating netback of $69.12 per boe
- Atlantic operating netback of $45.92 per barrel
Asia Pacific ChinaGross natural gas sales from the two producing fields at the Liwan Gas Project in the fourth quarter averaged 374 million cubic feet per day (mmcf/day), with associated liquids averaging 16,400 bbls/day (183 mmcf/day and 8,300 bbls/day Husky W.I.). Realized gas pricing at Liwan was $14.31 per mcf, with liquids pricing of $67.87 per barrel. Operating costs were $5.16 per boe, with an operating netback of $71.85 per boe.
At the Liuhua 29-1 field at Liwan, all seven wells have been drilled and completed. The wells will be tied into the existing subsea infrastructure, with first gas expected by 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. IndonesiaGross natural gas sales at the BD Project in the Madura Strait averaged 66 mmcf/day, with associated liquids production of 5,100 bbls/day (27 mmcf/day and 2,100 bbls/day Husky W.I.), which takes into account reduced volumes due to temporary processing constraints on the contracted floating production, storage and offloading (FPSO) vessel. Realized gas pricing at BD was $9.85 per mcf, with liquids pricing of $90.33 per barrel. Operating costs were $8.82 per boe, with an operating netback of $51.53 per boe.
Overall average production in the Atlantic region was approximately 24,400 bbls/day (Husky W.I.). This takes into account the suspension of production-related operations in the fourth quarter on the partner-operated Terra Nova FPSO, in which Husky has a 13% working interest. West White Rose Project
The final quadrant of the concrete gravity base was completed ahead of schedule and related topsides construction was progressed as the project advances on plan towards first oil around the end of 2022.
2019 RESERVES REPLACEMENT
The proved reserves life index was 13.5 years, comparable to 2018.
Total proved reserves before royalties at the end of 2019 were 1.43 billion boe, compared to 1.47 billion boe at the end of 2018. Proved plus probable reserves were 2.11 billion boe, compared to 2.54 billion boe at the end of 2018, which reflects reduced future capital spending at the Sunrise Energy Project and the Ansell natural gas resource play in Western Canada in the five-year plan.
Proved reserves additions of 174 million boe were primarily related to Lloydminster thermal projects, the Tucker Thermal Project, and the liquids-rich gas resource play at Wembley. These additions were partially offset by a 5 million boe reduction due to economic factors, and 103 million boe of negative technical revisions across the Company mainly associated with lower future capital spending in the five-year plan. Taking the additions and negative revisions into account, the one-year proved reserves replacement ratio was 67%, excluding economic factors (62% including economic factors).
The average three-year annual proved reserves replacement ratio was 166%, excluding economic factors (162% including economic factors), including dispositions in Western Canada of 62 million boe of proved reserves in 2017.