Quarterly / Earnings Reports | Third Quarter (3Q) Update

Husky Energy Reports Q3 2019 Results

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   |    Thursday,October 24,2019

Husky Energy continued to execute its 2019 business plan in the third quarter, with the delivery of all planned milestones in the Integrated Corridor and Offshore businesses.

Funds from operations were $1 billion, compared to $1.3 billion in the third quarter of 2018. Net earnings were $273 million. Cash flow from operating activities, including changes in non-cash working capital, was $800 million, compared to $1.3 billion in the third quarter of 2018. The reductions in funds from operations and net earnings include impacts from lower crude oil prices and lower U.S. refining margins.

“We achieved all of the milestones for the third quarter as set out at Investor Day in May, and remain on track for the rest of the year,” said CEO Rob Peabody. “We also saw our work to enhance process safety translate to improved reliability across the business.”

“In the Integrated Corridor, we started up our latest 10,000 barrel-per-day Saskatchewan thermal bitumen project at Dee Valley, which has already reached its nameplate capacity. We began the final tie-in of the Lima Refinery crude oil flexibility project, received permits to commence the Superior Refinery rebuild, and reached an agreement to sell the Prince George Refinery.”

In the Offshore business, the SeaRose floating production, storage and offloading (FPSO) vessel is back up to full rates, the Liuhua 29-1 project in China is 65% complete, and the West White Rose Project is now 52% complete.

In line with the reduced capital program set out at Investor Day in May 2019, earlier this week Husky took steps to further align its organization and workforce.

Highlights:

• Funds from operations of $1 billion, compared to $1.3 billion in the year-ago period
• Cash flow from operating activities of $800 million, compared to $1.3 billion in the third quarter of 2018
• Net earnings of $273 million, compared to net earnings of $545 million in Q3 2018
• Capital spending of $868 million was directed towards advancing the Saskatchewan thermal portfolio, the Lima crude oil flexibility project, and progressing construction of the Liuhua 29-1 field offshore China and the West White Rose Project in the Atlantic region. Capital expenditure guidance for 2019 remains unchanged at $3.3-$3.5 billion
• Free cash flow, before dividends, of $153 million
• Successful startup of the 10,000 barrel-per-day Dee Valley thermal bitumen project, which came in ahead of schedule and under budget
• Overall Upstream production averaged 294,800 barrels of oil equivalent per day (boe/day), which takes into account the return to full production at the White Rose field in the Atlantic region, mandated production quotas in Alberta and maintenance at the Liwan Gas Project and the BD Project in the Asia Pacific region; production was approximately 310,000 boe/day at the end of the third quarter
• Downstream throughput of 356,400 barrels per day (bbls/day), compared to 350,600 bbls/day in the third quarter of 2018
• Construction commenced on the Superior Refinery rebuild project; full operations expected to resume in 2021
• Reached an agreement to sell the Prince George Refinery for $215 million in cash plus a closing adjustment for working capital, and a contingent payment of up to $60 million over two years; sale is expected to close in the fourth quarter of 2019 subject to closing conditions

Q3 Summary

Upstream production averaged 294,800 boe/day, compared to 296,700 boe/day in the third quarter of 2018, which takes into account the start up of the 10,000 bbls/day Dee Valley thermal bitumen project in Saskatchewan and return to full production at the White Rose field in the Atlantic region, partially offset by ongoing mandated production quotas in Alberta and maintenance at Liwan and the BD Project.

Average realized pricing for Upstream production was $47.54 per boe compared to $50.44 per boe in the same period in 2018. Realized pricing for oil and liquids averaged $53.46 per barrel compared to $56.02 per barrel in the year-ago period, and natural gas pricing averaged $5.44 per thousand cubic feet (mcf), compared to $6.15 per mcf in Q3 2018. Upstream operating costs were $14.83 per boe compared to $14.68 per boe in the third quarter of 2018, reflecting lower production in the Atlantic region and maintenance at Liwan and the BD Project.

Upstream operating netbacks averaged $29.31 per boe compared to $31.30 per boe in the year-ago period.

Upgrader and refinery throughput was 356,400 bbls/day, compared to 350,600 bbls/day in the same period in 2018. This reflects strong performance at the Lima Refinery, which averaged 174,300 bbls/day in the third quarter.

The average realized U.S. refining and marketing margin was $12.17 US per barrel of crude oil throughput, which reflects an unfavourable first-in, first-out (FIFO) pre-tax inventory valuation adjustment of $0.13 US per barrel. This compared to $17.52 US per barrel a year ago, which included an unfavourable FIFO pre-tax inventory valuation adjustment of $0.35 US per barrel.

The Upgrader realized margin was $15.01 per barrel compared to $29.19 per barrel in the same period in 2018, which takes into account lower upgrading differentials.

Net earnings in the Infrastructure and Marketing segment were $34 million compared to $149 million in Q3 2018, due to tighter location pricing differentials.

Husky has already achieved most of its planned 2019 operational milestones and is making strong progress on its 2020 targets.

Ops Highlights

• Upstream production averaged 232,100 boe/day compared to 223,300 boe/day in Q3 2018
• Operating margin of $710 million, compared to $703 million in Q2 2019 and $1.03 billion in Q3 2018
• First oil achieved at the Dee Valley thermal bitumen project in Saskatchewan, which has reached its 10,000 bbls/day nameplate capacity
• Downstream throughput of 356,400 bbls/day compared to 350,600 bbls/day in the third quarter of 2018

Thermal Production                                                                    

Thermal bitumen production from Saskatchewan thermal projects, the Tucker Thermal Project and the Sunrise Energy Project averaged 126,400 bbls/day (Husky W.I.), compared to 117,300 bbls/day (Husky W.I.) in Q3 2018.

Overall production from the Saskatchewan thermal portfolio was 76,900 bbls/day compared to 74,300 bbls/day in Q3 2018. This included the startup of the new 10,000 bbls/day Dee Valley thermal project, which began production ahead of schedule in August and achieved its nameplate capacity in September.

Five new Saskatchewan thermal bitumen projects with a combined nameplate capacity of 50,000 bbls/day are being advanced through 2023, including the Spruce Lake Central development, scheduled for startup in the second half of 2020, and the Spruce Lake North project, which is planned to start up around the end of 2020.

Resource Plays

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 while supporting the natural gas requirements of its thermal operations in Western Canada.

In the oil and liquids-rich Montney formation, one well was drilled in the Karr area, completing the planned 2019 Montney drilling program. Ten Montney wells at Wembley and Karr are expected to be brought on production in the fourth quarter.

OFFSHORE                                               

• Overall average net production of 62,700 boe/day, compared to 73,400 boe/day in the third quarter of 2018
• Operating netback of $55.53 per boe
  • Asia Pacific operating netback of $62.59 per boe
  • Atlantic operating netback of $41.64 per barrel
• White Rose field returned to full operations           

Asia Pacific
               
China
Natural gas sales from the two producing fields at the Liwan Gas Project averaged 323 million cubic feet per day (mmcf/day), with associated liquids averaging 14,300 bbls/day (158 mmcf/day and 6,600 bbls/day Husky W.I.). Realized gas pricing at Liwan was $13.28 per mcf, with liquids pricing of $61.81 per barrel. Operating costs were $6.10 per boe, with an operating netback of $65.67 per boe.

At the Liuhua 29-1 field at Liwan, all seven wells have been drilled, with final completions under way. The wells will be tied in to 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.
                                                                                              
Indonesia
Natural gas sales at the BD Project in the Madura Strait averaged 86 mmcf/day, with liquids production of 7,000 bbls/day (35 mmcf/day and 2,800 bbls/day, Husky W.I.). Volumes were impacted by maintenance to the leased FPSO vessel. Realized gas pricing at BD was $9.82 per mcf, with liquids pricing of $83.03 per barrel. Operating costs were $6.22 per boe, with an operating netback of $51.98 per boe.

Atlantic

Overall average production in the Atlantic region was approximately 21,000 bbls/day (Husky W.I.), reflecting the return to operations in August of the final two drill centres in the White Rose field.
                                                                                                                                        
West White Rose Project                                                  
Construction work on the concrete gravity structure and related topsides is progressing. The third quadrant of the concrete gravity structure (CGS) and two interior decks were completed, and the fourth and final CGS quadrant was completed in October. The project is now 52% complete as it advances towards first oil around the end of 2022.

Corporate Developments

The Board of Directors has approved a quarterly dividend of $0.125 per common share for the three-month period ended September 30, 2019. The dividend will be payable on January 2, 2020 to shareholders of record at the close of business on December 2, 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 December 31, 2019. The dividends will be payable on December 31, 2019 to holders of record at the close of business on December 2, 2019.