THIRD QUARTER RESULTS
Husky Energy generated funds from operations of $1.3 billion in the third quarter and free cash flow of $350 million.
Upstream production averaged 297,000 boe/day, which reflects a turnaround at the Tucker Thermal Project, planned maintenance at the Sunrise Energy Project, the decision to slow the pace of CHOPS well optimizations, third-party gas and power constraints and lower than anticipated Atlantic production due to well performance. This compared to 318,000 boe/day in the third quarter of 2017 and 296,000 bbls/day in the second quarter of 2018.
Average realized pricing for Upstream production was $50.44 per boe, compared to $40.05 per boe in the year-ago period. Realized pricing for oil and liquids averaged $56.02 per barrel, and natural gas averaged $6.15 per thousand cubic feet (mcf).
Upstream operating costs averaged $14.68 per boe, compared to $14.12 per boe in Q3 2017. Upstream operating netbacks averaged $31.30 per boe compared to $23.25 per boe in Q3 2017.
Downstream throughput was 350,600 bbls/day compared to 374,000 bbls/day in the third quarter of 2017, which includes the turnaround at Lima starting in mid-September this year.
The Chicago 3:2:1 crack spread averaged $19.04 US per barrel compared to $19.30 US per barrel in Q3 2017. Average realized U.S. refining margins were $17.52 US per barrel, which takes into account a pre-tax FIFO loss of $0.34 US per barrel. This compared to $14.98 US per barrel a year ago, which included a pre-tax FIFO adjustment gain of $1.74 US per barrel.
Upgrading net earnings were $88 million, compared to $9 million in the third quarter of 2017. Upgrading margins were $29.19 per barrel, compared to $12.32 per barrel in the year-ago period.
Net earnings in the Infrastructure and Marketing segment were $149 million, compared to $10 million in Q3 2017. This was primarily due to the wider WTI/WCS differential, which averaged $29.09 per barrel compared to $12.44 in the third quarter of 2017.
Infrastructure and Marketing realized margins were $202 million, compared to $14 million in Q3 2017, reflecting, in part, the value captured from the Company's long-term 75,000 bbls/day committed export capacity on the Keystone pipeline and 160 mmcf/day in natural gas pipeline capacity to U.S. markets.
Net debt at the end of the quarter was $2.6 billion.
- Upstream average production of 223,000 boe/day
- Upstream operating netback of $19.75 per boe, including an operating netback of $30.63 per barrel from thermal operations
- Downstream throughput of 350,600 bbls/day
- Downstream upgrading/refining margin of $25.27 per barrel
Thermal bitumen production from Lloyd thermal projects, Tucker and Sunrise averaged 117,300 bbls/day (Husky working interest), compared to 117,700 bbls/day (Husky working interest) in the third quarter of 2017. This takes into account the turnaround at Tucker, planned maintenance at Sunrise and third-party gas and power constraints.
Overall thermal operating costs were $12.04 per barrel.
Rush Lake 2 achieved first oil in October and is expected to ramp up to its 10,000 bbls/day design capacity by the first quarter of 2019.
In addition, the Company is currently developing five 10,000 bbls/day Lloyd thermal bitumen projects, with a combined design capacity of 50,000 bbls/day coming online by the end of 2021.
- Construction at Dee Valley has been advanced, with first oil now expected in the fourth quarter of 2019, six months sooner than expected at Investor Day in May.
- At Spruce Lake Central, construction has started on the central processing facility and drilling on the first well pad has been completed. First production is expected in 2020.
- Site clearing is underway at Spruce Lake North, with first oil expected around the end of 2020.
- Two additional 10,000 bbls/day thermal bitumen projects remain on track to be brought online in the second half of 2021.
Tucker averaged production of 18,300 bbls/day, reflecting the three-week turnaround completed in the quarter. Since the turnaround, it has achieved a peak daily rate of 30,000 bbls/day.
At Sunrise, average production in the quarter was 49,400 bbls/day (24,700 bbls/day Husky working interest), reflecting maintenance on the once-through steam generators. This compares to 40,500 bbls/day (20,250 bbls/day Husky working interest) in the year-ago period.
The Company remains focused on capital-efficient operations in Edson, Grand Prairie and Rainbow Lake, its three core Western Canada hubs.
An accelerated drilling program that was increased from an 18 to a 25-well program in the Ansell and Kakwa areas of the Wilrich formation is progressing, with 15 wells drilled and 13 completed. In the oil and liquids-rich Montney formation, four wells have been drilled as part of a 2018 program of up to eight wells, primarily in the Wembley and Karr areas. Three have been completed.
Husky Midstream Limited Partnership is progressing construction on the new Corser gas processing plant in the Ansell area of Central Alberta. It is expected to add 120 mmcf/day of processing capacity when it starts up in the fourth quarter of 2019.
Total Canadian refining throughput, including the Lloydminster Upgrader and the Lloydminster Asphalt Refinery, averaged 116,500 bbls/day, with EBITDA of $243 million.
In the U.S., total refining throughput was 234,100 bbls/day. At the Lima Refinery, throughput averaged 163,300 bbls/day compared to 178,300 bbls/day in the third quarter of 2017, including a scheduled turnaround starting in mid-September. A crude oil flexibility project to increase heavy oil processing capacity from the current 10,000 bbls/day to 40,000 bbls/day by the end of 2019 is on track.
Operations at the Superior Refinery remain suspended, and an investigation into the cause of the April 26th incident is ongoing. The Company is currently focused on winterizing the site. An engineering contractor has been appointed to oversee design work for the rebuild, with the rebuild beginning once the investigation and design work are complete. Normal operations are not expected to resume until 2020. In the quarter Husky accrued $110 million in insurance proceeds for asset damage and repair costs.
- Average production of 73,400 boe/day
- Operating netback of $66.34 per boe° Asia Pacific operating netback of $65.45 per boe° Atlantic operating netback of $68.20 per barrel
At the Liwan Gas Project, gross production from the two producing fields averaged 371 mmcf/day in sales gas volumes, with associated liquids averaging 16,500 bbls/day (182 mmcf/day and 8,400 bbls/day Husky working interest). This reflects continued strong demand in China and five days of downtime related to typhoon season.
The Company realized gas pricing of $13.14 Cdn per mcf, with liquids pricing of $76.13 Cdn per barrel.
Construction at Liuhua 29-1, the third deepwater field at Liwan, is underway with detailed design work in progress. Drilling of three additional wells is scheduled to commence in the fourth quarter of 2018, adding to the four wells previously drilled. All three wells will be tied into the existing Liwan infrastructure. First gas is anticipated around the end of 2020, with target net production of 45 mmcf/day gas and 1,800 bbls/day liquids when fully ramped up, reflecting Husky's 75 percent working interest.
The Company is progressing commercial development plans following the successful drilling of an oil exploration well on Block 15/33 in the South China Sea, approximately 160 kilometres southeast of Hong Kong. Husky is the operator during the exploration phase, with a working interest of 100 percent in the wells. CNOOC may assume operatorship and up to a 51 percent working interest, with exploration cost recovery from production allocated to Husky.
During the quarter, an exploration well was drilled on the nearby Block 16/25. The results will be evaluated further.
At the liquids-rich BD Project, gross gas sales averaged 100 mmcf/day with associated liquids production of 10,400 bbls/day (40 mmcf/day and 4,200 bbls/day Husky working interest). Liquids production was 40 percent higher than expected. BD gas was sold into the East Java market at contracted rates for a realized price of $9.79 Cdn per mcf, with liquids pricing of $95.61 Cdn per barrel.
At the combined MDA-MBH fields in the Madura Strait, seven production wells are scheduled to be drilled in 2019 and come online in 2020.
Construction was completed on the base slab of the West White Rose Project's concrete gravity structure, and slipforming of the column is underway. Work continues on the topsides and living quarters. First oil is anticipated in 2022, with West White Rose expected to reach peak production of 75,000 bbls/day (52,500 bbls/day Husky working interest) in 2025 as development wells are drilled and brought online.
At the North Amethyst infill well, remediation work to address a high water cut was unsuccessful and future intervention options on this well are being evaluated. Two well workovers were completed at the White Rose field during the quarter and two additional infill wells are scheduled to come online in the fourth quarter of 2018. These are part of a program to offset reservoir declines at the White Rose field and its satellite extensions until the startup of West White Rose in 2022.
Evaluation of the successful White Rose A-24 well is ongoing.