CALGARY, Alberta, Dec. 04, 2017 (GLOBE NEWSWIRE) — Husky (TSX:HSE) is on track to exceed the 2018 targets for funds from operations and free cash flow outlined at its 2017 Investor Day.
“We are ahead of our five-year plan in delivering cost efficiencies, lower cost production, lower operating costs, lower sustaining capital requirements, and increasing free cash flow,” said CEO Rob Peabody.
2018 Plan Highlights:
- Funds from operations are anticipated to exceed $4 billion and free cash flow is expected to be about $1 billion at pricing of $55 US WTI, $2.50 AECO and a $15 US per barrel Chicago 3:2:1 crack spread
- Capital spending of $2.9-3.1 billion: $1.0-1.1 billion growth capital and $1.9-2.0 billion sustaining and corporate capital
- Current net debt of $3.3 billion, representing approximately one times net debt to expected 2017 funds from operations, anticipated to remain well below target of less than two times 2018 funds from operations
- New project funding is contingent on meeting a forecast minimum 10 percent rate of return at $45 US WTI
- 2018 annual production is expected to average 320,000-335,000 barrels of oil equivalent per day (boe/day), despite 20,000 boe/day in 2017 asset sales expected to close by year end. Thermal bitumen production is expected to grow 12 percent and Asia Pacific production is anticipated to grow 16 percent
- 2021 production target of 400,000 boe/day, representing a seven percent compound average annual growth rate
- Average Upstream operating cost target of $13-13.50 per barrel, down 18 percent from $16.12 per barrel in 2014
- Earnings break-even oil price expected to be about $42 US WTI per barrel with cash break-even of $32 US WTI per barrel
- Two 10,000-barrels-per-day (bbls/day) Lloyd thermal bitumen projects and Liuhua 29-1 have been sanctioned and are forecast to start up in 2021
Husky’s operational focus in 2018 is to ramp up the Tucker Thermal Project, Phase 1 of the Sunrise Energy Project and the BD Project in Indonesia to full rates. In addition, the Company will integrate its newly-acquired Superior Refinery, advance six Lloyd thermal projects, move forward with the Liuhua 29-1 field development offshore China and progress the West White Rose Project offshore Newfoundland and Labrador.
|2018 CAPITAL INVESTMENT AND PRODUCTION1|
|Capital Budget ($ millions)||Production (mbbls/day)|
|Crude Oil and Liquids||2017 Budget||2018 Budget||2017 Guidance||2018 Guidance|
|Thermal bitumen (Lloyd, Tucker, Sunrise)||560 – 590||895 – 930||120 – 127||128 – 137|
|Non-thermal heavy, light, medium, NGLs||165 – 175||140 – 150||63 – 66||67 – 69|
|Atlantic light||475 – 500||750 – 775||35 – 37||34 – 35|
|Asia Pacific light and NGLs||– –||– –||13 – 15||10 – 11|
|Total Crude Oil and Liquids||1,200 – 1,265||1,785 – 1,855||231 – 245||240 – 252|
|Canada||190 – 200||215 – 225||365 – 375||280 – 290|
|Asia Pacific||80 – 85||130 – 150||165 – 170||200 – 210|
|Total Natural Gas||270 – 285||345 – 375||530 – 545||480 – 500|
|Total Upstream||1,470 – 1,550||2,130 – 2,230||320 – 335 (mboe/day) 320 – 335|
|Canada||300 – 325||130 – 160|
|U.S.||320 – 340||580 – 625|
|Total Downstream||620 – 665||710 – 785|
|Total Corporate Capital||95 – 110||100 – 110|
|Total Capital Investment||2,185 – 2,325||2,940 – 3,125|
|Total Sustaining Capital||1,750 – 1,850||1,775 – 1,875|
1 Amounts exclude asset retirement obligations, capitalized interest and administration. Some figures rounded; see full Guidance report at huskyenergy.com
2018 Capital Program
Total capital spending is expected to be $2.9-3.1 billion, less than the estimated $3.3 billion annual average capital spending forecast in the five-year plan at Investor Day 2017, reflecting greater capital efficiency.
Upstream project spending is expected to be largely allocated to growing the Lloyd thermal portfolio, with 60,000 bbls/day of new production scheduled to be brought online between 2019 and 2021, and the construction of the 75,000-bbls/day West White Rose Project in the Atlantic region (52,500 bbls/day Husky working interest), with first oil planned in 2022.
The Board has sanctioned the Liuhua 29-1 project, the third deepwater gas field at the Liwan Gas Project. Construction is anticipated to begin in 2018, followed by first production in 2021.
The capital program remains flexible, with about 75 percent of Upstream spending directed toward short and medium-cycle projects. Downstream project spending includes the Lima crude oil flexibility project, which will add 30,000 bbls/day of additional heavy oil capacity by 2019, and a project to increase heavy oil processing capacity at the Superior Refinery.
Capital spending for 2017, not including the acquisition of the Superior Refinery, remains within guidance at $2.2-2.3 billion. Including the acquisition, which closed in November, total capital spending in 2017 is expected to be about $2.9 billion.
2018 Upstream Production
Average annual production is expected to be in the range of 320,000-335,000 boe/day. Adjusting for dispositions and asset sales expected to close by the end of 2017, this constitutes a six percent year-over-year increase in growth at the midpoint of this range, ahead of the Company’s five-year plan.
Husky has agreed to sell the Ram River Gas Plant and select legacy assets in Western Canada representing 18,000 boe/day of gas-weighted production. The transactions, which are expected to close by the end of 2017, were not included in the five-year plan presented at Investor Day 2017.
The Western Canada asset disposition program is now substantially complete. Since December 2015, about 52,000 boe/day of higher-cost legacy production has been sold or is expected to be sold by the end of 2017, with an associated reduction in asset retirement obligations of approximately $840 million. Over the same period, Husky added approximately 66,000 boe/day of new, lower-cost production, largely from the thermal and Offshore businesses.
With the ramp-up of the Tucker Thermal Project and Sunrise Energy Project toward full capacity, average annual thermal production is expected to grow 12 percent year over year.
In Western Canada, the Company plans to drill 17 net liquids-rich gas wells in the Wilrich formation in the Ansell and Kakwa areas. In the Montney formation, eight wells are scheduled to be drilled.
In the Asia Pacific region, production is anticipated to grow 16 percent year over year as the BD Project ramps up to full capacity offshore Indonesia.
In the Atlantic region, two infill wells are planned in the Jeanne d’Arc Basin. The first is scheduled to be drilled at the North Amethyst satellite extension in the first quarter and the second well at the main White Rose field is planned in the third quarter. The net peak production rate of each well is expected to be approximately 4,400 bbls/day.
Annual production in 2017 is expected to average approximately 324,000 boe/day, within the guidance range of 320,000-335,000 boe/day, despite the sale of assets representing about 2,500 boe/day of annualized production.
The Company expects to remain on track to achieve an average annual proved reserve replacement ratio of more than 130 percent in the 2017-2021 timeframe.
2018 Downstream Throughputs
Downstream net throughputs are expected to increase seven percent to approximately 360,000-370,000 bbls/day, compared to average 2017 throughputs of about 342,000 bbls/day.
At the Lima Refinery, the crude oil flexibility project to increase heavy oil processing capacity from 10,000 bbls/day to 40,000 bbls/day is continuing. A project to increase heavy oil processing capacity at the Superior Refinery will be completed in the first half of 2018.
Improving Cost Structure and Efficiencies
Husky continues to realize efficiencies across the business as it further reduces its cost structure and invests in higher return production:
- The Company’s gas price realizations in 2013, prior to the startup of the Liwan Gas Project in early 2014, averaged $3.19 per thousand cubic feet (mcf). Year to date in 2017, gas price realizations have averaged $5.39 per mcf, compared to average AECO pricing of about $2.15 per mcf. This reflects growing high-netback, fixed-price gas production in the Asia Pacific region and the disposition of legacy gas assets in Western Canada.
- The 10,000-bbls/day Rush Lake 2 thermal project has been accelerated and is expected to come on production in the first quarter of 2019.
- Improved operating efficiencies have resulted in faster drilling times at the Ansell and Kakwa resource plays. Drilling days have been reduced by 30 percent since the start of 2017, contributing to a 22 percent reduction in per-well drilling costs.
- A planned 16-well drilling program targeting the Wilrich formation was completed. Due in part to increased rig efficiency, two additional wells scheduled for 2018 were drilled in the fourth quarter of 2017.
- The Atlantic infill well drilling program has been accelerated as a result of drilling and installation efficiencies. Two wells originally planned for 2018 were advanced to 2017. The first well at the main White Rose field was drilled at the end of the third quarter and is now on production. A second well at North Amethyst is currently drilling, with first oil expected in early 2018.
Average Upstream operating costs continue to decrease and are expected to be in the range of $13-$13.50 per boe, compared to 2017 year-to-date operating costs of about $14 per boe, and Husky remains on track to achieve the 2021 target set at Investor Day 2017 of less than $12 per boe.
Downstream operating costs for the Lloydminster Upgrader and U.S. refineries along the Integrated Corridor are expected to average $6-7 per barrel.
Overall sustaining capital requirements are expected to be in the range of $1.8-1.9 billion.
The Company’s earnings break-even oil price is expected to be about $42 US WTI per barrel, compared to $43.60 US WTI per barrel in 2017. The cash break-even oil price is expected to be about $32 US WTI per barrel, compared to $33.50 US WTI per barrel in 2017.
Husky is moving ahead with several projects expected to contribute to a compound annual production growth rate of seven percent over the next four years, with production rising to 400,000 boe/day in 2021.
|Integrated Corridor||Net Production Capacity
|2017 Investor Day
|Tucker Thermal Project ramp-up||To 30,000||YE 2018||YE 2018|
|Sunrise Energy Project (14 additional wells)||11,500||Q4 2017 startup||Completed|
|Rush Lake 2||10,000||1H 2019||Accelerated to Q1 2019|
|Dee Valley||10,000||2020||1H 2020|
|Spruce Lake North||10,000||2020||2H 2020|
|Spruce Lake Central||10,000||2020||2H 2020|
|Edam Central||10,000||Planned||2H 2021|
|Future Lloyd thermal projects||10,000 per project||Average two per year||Planned|
|Ansell-Kakwa drilling program||–||16 Wilrich wells||18 Wilrich wells|
|Montney drilling program||–||Four wells||Finished|
|Lima Refinery crude oil flexibility project||30,000 (heavy)||2018-2019||2018-2019|
|Superior Refinery flexibility project||Up to 5,000 (heavy)||N/A||1H 2018|
|Lloydminster Refinery asphalt expansion||30,000||Under consideration||Superior Refinery delivering benefits in 2018|
|Offshore||Net Production Capacity||2017 Investor Day Guidance||Current Status|
|Liuhua 29-1 startup||30 mmcf/day / 1,200 bbls/day||2021||2021|
|BD Project startup||40 mmcf/day / 2,400 bbls/day||2H 2017||Completed|
|MDA-MBH, MDK gas fields startup||60 mmcf/day||2018-2019||2019|
|South White Rose infill well||4,500 bbls/day||Q4 2017||Completed in Q3 2017|
|White Rose infill well||4,500 bbls/day||Q2 2018||Accelerated to Q4 2017|
|North Amethyst infill well||4,300 bbls/day||Q4 2018||Accelerated to Q1 2018|
|White Rose infill well||4,500 bbls/day||Ongoing infill program||Q3 2018|
|West White Rose Project||52,500 bbls/day||First oil in 2022||2022|
1 Expected net peak production rates.
2018 Planned Maintenance and Turnarounds
- A five-week partial turnaround at the Lloydminster Upgrader in the second quarter; expected utilization rate of 70 percent during the maintenance period.
- A five-week full plant turnaround at the Superior Refinery in the second quarter.
- A five-week partial turnaround at the Lima Refinery in the fourth quarter; expected utilization rate of 50 percent during the maintenance period.
- A three-week turnaround at the SeaRose FPSO (floating production, storage and offloading) vessel starting in the second quarter.
- A four-week turnaround at the Terra Nova FPSO in the third quarter.
CONFERENCE CALL AND INVESTOR PRESENTATION
An investor presentation has been posted on the Company’s website at www.huskyenergy.com
A conference call will be held on Monday, December 4 at 9 a.m. Mountain Time (11 a.m. Eastern Time) to discuss the Company’s 2018 production and capital expenditure guidance.
CEO Rob Peabody, CFO Jon McKenzie and COO Rob Symonds will participate in the call.
|To listen live:
Canada and U.S. Toll Free: 1-800-319-4610
|To listen to a recording (after 10 a.m. Dec. 4)
Canada and U.S. Toll Free: 1-800-319-6413
Investor and Media Inquiries:
Rob Knowles, Manager, Investor Relations
Mel Duvall, Manager, Media & Issues