Husky Energy Reports Third Quarter 2020 Results
This news release contains references to the non-GAAP financial measures “funds from operations”, “free cash flow”, “net debt”, “operating margin”, and “net debt to trailing funds from operations”. Please refer to “Non-GAAP Measures” at the end of this news release.
CALGARY, Alberta, Oct. 29, 2020 (GLOBE NEWSWIRE) -- Husky Energy (TSX: HSE) recorded funds from operations of $148 million in the third quarter. Cash flow from operating activities was $79 million, including changes in non-cash working capital of $69 million.
“We are continuing to take steps to protect our balance sheet and generate free cash flow, with a priority of returning cash to our shareholders,” said CEO Rob Peabody. “While oil prices showed gradual improvement during the third quarter, we were impacted by lagging U.S. refining margins, turnarounds at several facilities and a significant non-cash impairment related to lower long-term commodity price assumptions and market indicators, including the recently announced transaction. However, the startup of a number of projects will increase funds from operations and provide for further stability in this challenging market environment.”
Added Peabody: “We are confident that the combination with Cenovus will deliver significant long-term value by creating a larger, stronger and more resilient Canadian integrated energy producer. Over the next few months while the transaction is pending, we will maintain our focus on safe and reliable operations, while planning for a seamless integration to facilitate the accelerated return of capital to shareholders.”
First oil was achieved in August at Spruce Lake Central, Husky’s most recent 10,000-barrel-per-day thermal bitumen project to be brought on production. The project was completed on schedule and on budget with enhanced COVID-19 health and safety protocols in place. The project is expected to ramp up towards full capacity in the fourth quarter. Following a planned turnaround, the Company has increased its diesel capacity at the Lloydminster Upgrader from 6,000 barrels per day (bbls/day) to nearly 10,000 bbls/day.
In the Asia Pacific region, the Liuhua 29-1 natural gas field was commissioned during the quarter and first production and sales are expected in early November.
In the Atlantic region, Husky and its partners have cancelled the 2021 construction season for the West White Rose Project and are moving the project into safekeeping mode. The decision is in line with the Company’s drive to reduce costs, limit net debt and protect its balance sheet and ample liquidity.
On October 25, 2020, Husky announced that it entered into a definitive agreement with Cenovus Energy Inc., under which Husky and Cenovus will combine in an all-stock transaction to create a leading Canadian integrated energy company. Under the terms of the agreement, which was unanimously approved by the Board of Directors of each company, Husky shareholders will receive 0.7845 of a share of Cenovus plus 0.0651 of a warrant to acquire a share of Cenovus in exchange for each Husky common share they own. Each warrant will entitle the holder to acquire one Cenovus common share for a period of five years following completion of the transaction at an exercise price of $6.54. Upon the exercise of such warrants, the company would receive approximately $428 million in cash proceeds. Immediately following the close of the transaction, and prior to the exercise of any warrants issued to Husky shareholders as part of the transaction, Cenovus shareholders will own approximately 61% of the combined company, and Husky shareholders will own approximately 39%. The transaction is expected to close in Q1 2021, subject to regulatory approvals, Court of Queen’s Bench of Alberta approval and customary closing conditions. The proposed transaction is structured as a plan of arrangement and is subject to the approval of both Husky and Cenovus shareholders at special meetings to be held to vote on the arrangement.
THIRD QUARTER SUMMARY
- Funds from operations were $148 million compared to $1 billion in the third quarter of 2019.
- Cash flow from operating activities was $79 million, including changes in non-cash working capital, compared to $800 million in Q3 2019.
- The net loss was $7 billion, reflecting non-cash impairments of $6.7 billion (after tax), which were related to lower long-term commodity price assumptions and reduced capital investment. In addition, higher discount rates were used based off of a number of factors and market indicators, including the recently announced combination with Cenovus.
- Capital expenditures were $354 million, including $79 million in Superior Refinery rebuild capital.
- Net debt at the end of the third quarter was $5.4 billion. Total liquidity was $5.5 billion, comprised of $1 billion in cash and $4.5 billion in available credit facilities. Liquidity was improved with a $1.25 billion public notes offering at a coupon of 3.5%. Net proceeds were used, in part, to repay revolving debt and the Company’s $500 million term loan in early October.
- Total upstream production averaged 258,400 barrels of oil equivalent per day (boe/day) compared to 294,800 boe/day in the third quarter of 2019 and 246,500 boe/day in the second quarter of 2020. This reflects the ramp-up of production at Lloydminster thermal projects and the Sunrise Energy Project, partially offset by a third-party condensate pipeline outage in September, a planned turnaround on the SeaRose floating production, storage and offloading (FPSO) vessel and a planned turnaround at the Tucker Thermal Project that began in September and is now completed.
- Integrated Corridor production averaged 194,500 boe/day, compared to 175,400 boe/day in the second quarter of 2020.
- Downstream throughput averaged 300,100 bbls/day, compared to 281,300 bbls/day in the second quarter of 2020. This takes into account a planned turnaround at the Lloydminster Upgrader, which is now completed.
- Offshore production averaged 63,900 boe/day, compared to 71,100 boe/day in the second quarter of 2020, Husky working interest.
|Three Months Ended||Nine Months Ended|
|Upstream production2 (mboe/day)||194||175||232||202||226|
|Upgrader and refinery throughput3 (mbbls/day)||300||281||356||296||343|
|Offshore production2 (mboe/day)||64||71||63||66||57|
|Revenue, net of royalties4 ($mm)||3,326||2,378||5,292||9,772||15,069|
|Operating margin5 ($mm)||277||239||931||347||2,804|
|Funds from operations5 ($mm)||148||18||1,021||191||2,782|
|Per common share – Basic ($/share)||0.15||0.02||1.02||0.19||2.77|
|Cash flow – operating activities ($mm)||79||(10||)||800||424||2,105|
|Capital expenditures6 ($mm)||354||310||868||1,276||2,538|
|Free cash flow5 (loss) ($mm)||(206||)||(292||)||153||(1,085||)||244|
|Net earnings (loss) ($mm)||(7,081||)||(304||)||273||(9,090||)||971|
|Per common share – Basic ($/share)||(7.05||)||(0.31||)||0.26||(9.07||)||0.94|
|Net debt5 ($ billions)||5.4||5.1||3.9||5.4||3.9|
|Net debt to trailing funds from operations5 (times)||8.2||3.3||1.1||8.2||1.1|
|1Includes Lloydminster Heavy Oil Value Chain, Oil Sands, Western Canada Production, U.S. Refining and Canadian Refined Products. |
2Refer to advisory for full product breakdown.
32019 refinery throughput includes the Prince George Refinery, which was sold in November 2019.
4Revenue, net of royalties results reported for 2019 have been recast to reflect a change in reclassification of intersegment sales eliminations and a change in presentation of the Integrated Corridor and Offshore business units.
5Non-GAAP measure; refer to advisory.
6Includes Superior Refinery rebuild costs; expected to be largely covered by insurance.
- Overall operating margin of $111 million
- Average upstream production of 194,500 boe/day
- Downstream throughput of 300,100 bbls/day
Lloydminster Heavy Oil Value Chain
The Lloydminster Heavy Oil Value Chain (LHOVC) includes the Lloydminster and Tucker thermal projects and enhanced oil recovery (EOR) assets, cold heavy oil production with sand (CHOPS), and the Lloydminster Upgrader and Asphalt Refinery.
The LHOVC operating margin was $136 million, compared to $5 million in the second quarter of 2020, reflecting improved pricing partially offset by higher blending costs due to higher condensate prices.
Sales of synthetic crude oil (SCO) and refined products averaged 77,600 bbls/day, compared to 78,800 bbls/day in the second quarter. Blended crude oil sales averaged 88,900 bbls/day, compared to 86,600 bbls/day in Q2 2020.
Lloydminster Upgrader throughput was 51,600 bbls/day, compared to 65,700 bbls/day in the second quarter of 2020, which takes into account the start of a planned turnaround. Lloydminster Asphalt Refinery throughput was 27,100 bbls/day, compared to 28,200 bbls/day in the previous quarter.
Total LHOVC thermal bitumen production averaged 94,300 bbls/day, compared to 82,300 bbls/day in the second quarter. CHOPS and EOR crude production was 21,400 bbls/day, compared to 19,800 bbls/day in Q2 2020.
SCO and refined products realized pricing averaged $60.86 per barrel, compared to $44.44 per barrel in Q2 2020. Realized pricing for blended crude oil averaged $41.03 per barrel, compared to $24.36 per barrel in the previous quarter. LHOVC operating costs were $11.28 per boe, compared to $9.72 per boe in the second quarter of 2020. The operating margin was $11.03 per boe, compared to $6.88 per boe in the previous quarter.
Production from the Spruce Lake Central thermal project continues to ramp up towards full capacity, exiting the third quarter at approximately 5,000 bbls/day.
The Sunrise Energy Project averaged 46,200 bbls/day (23,100 bbls/day Husky working interest), compared to 25,600 bbls/day (12,800 bbls/day Husky working interest) in the previous quarter.
Western Canada Production
Total production averaged 55,700 boe/day, compared to 60,500 boe/day in the second quarter of 2020. Capital expenditures and development activities remained at minimum levels in the third quarter.
The U.S. Refining operating margin was a loss of $81 million, compared to a margin of $46 million the previous quarter, reflecting lower realized refining margins.
U.S. refinery throughput averaged 221,400 bbls/day, compared to 187,400 bbls/day in the second quarter. Average throughput at the Lima Refinery was 153,700 bbls/day, compared to 130,000 bbls/day in the previous quarter, reflecting the continued optimization of refinery runs to match product demand.
The Chicago 3:2:1 crack spread averaged $7.66 US per barrel, compared to $6.15 US per barrel in Q2 2020.
The average realized U.S. refining and marketing margin was $4.64 US per barrel of crude oil throughput, which included the impacts of inventory valuations and a favourable FIFO pre-tax inventory valuation adjustment of $2.22 US per barrel. This compared to $11.25 US per barrel in the previous quarter, which included an unfavourable FIFO pre-tax inventory valuation adjustment of $2.34 US per barrel.
Husky continues to progress the rebuild project at the Superior Refinery under strict health and safety protocols. The recovery of business and property damage insurance payments related to the refinery is expected to increase in future quarters as activity levels increase.
- Overall operating margin of $239 million
- Average net production of 63,900 boe/day
- Operating margin of $54.75 per boe
Natural gas sales from the two producing fields at the Liwan Gas Project averaged 191 million cubic feet per day (mmcf/day), Husky working interest with associated liquids sales of 8,400 bbls/day, Husky working interest. This compared to 211 mmcf/day of gas and 9,300 bbls/day of liquids in the second quarter, reflecting end-user management of annual purchase volumes from the Liuhua 34-2 field in the second half of 2020 to fully meet contractual gas purchase obligations.
Commissioning was completed ahead of schedule at the Liuhua 29-1 field at the Liwan Gas Project, with first gas production and sales on track to start in early November. The field has been tied into the existing infrastructure at Liwan, which includes the Liwan 3-1 and Liuhua 34-2 fields.
Total natural gas sales at the BD Project in the Madura Strait averaged 87 mmcf/day, with associated liquids sales of 7,700 bbls/day (35 mmcf/day and 3,100 bbls/day, Husky working interest).
Overall production in the Atlantic region averaged 14,800 bbls/day, Husky working interest. This takes into account a planned turnaround on the SeaRose FPSO vessel and the ongoing suspension of production-related operations on the partner-operated Terra Nova FPSO, in which Husky has a 13% working interest.
At the West White Rose Project, major construction activities will not proceed in 2021 given the current weak market environment. The project will continue to be assessed as the external environment evolves.
Husky completed a public offering of $1.25 billion of notes in the third quarter. The net proceeds of this offering were used, in part, to repay revolving debt and the Company’s $500 million term loan in early October.
Non-cash impairments totalled $6.7 billion (after tax) and were related to lower long-term commodity price assumptions and management’s decision to reduce capital investments. In addition, higher discount rates were used based off of a number of factors and market indicators, including the recently announced combination with Cenovus.
Husky expects the strategic combination with Cenovus to close in the first quarter of 2021, subject to customary closing conditions and regulatory approvals, including the approval of shareholders of both companies. The Board of Directors of each of Cenovus and Husky have unanimously approved the arrangement agreement and support the transaction. Details of the transaction will be included in a joint information circular that Cenovus and Husky expect to mail to their respective shareholders by mid-November. The special shareholder meetings of both companies are expected to be held in December.
The Board of Directors has approved a quarterly dividend of $0.0125 per common share for the three-month period ended September 30, 2020. The dividend will be payable January 4, 2021 to shareholders of record at the close of business on December 1, 2020.
Regular dividend payments on each of the Cumulative Redeemable Preferred Shares – Series 1, Series 2, Series 3, Series 5 and Series 7 – will be paid for the three-month period ended December 31, 2020. The dividends will be payable on December 31, 2020 to holders of record at the close of business on December 1, 2020.
|Share Series||Dividend Type||Rate (%)||Dividend Paid ($/share)|
A conference call will be held on Thursday, October 29 at 10 a.m. Mountain Time (12 p.m. Eastern Time) to discuss Husky’s third quarter results. CEO Rob Peabody, CFO Jeff Hart and other members of the senior executive team will participate in the call.
|To listen live:|
Canada and U.S. Toll Free: 1-800-319-4610
Outside Canada and U.S.: 1-604-638-5340
|To listen to a recording (after 11 a.m. MT on Oct. 29):|
Canada and U.S. Toll Free: 1-800-319-6413
Outside Canada and U.S.: 1-604-638-9010
Duration: Available until November 29, 2020
Audio webcast: Available for 90 days at www.huskyenergy.com
Investor and Media Inquiries:
Leo Villegas, Director, Investor Relations
Kim Guttormson, Manager, Communication Services
Certain statements in this news release are forward-looking statements and information (collectively, “forward-looking statements”), within the meaning of the applicable Canadian securities legislation, Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended. The forward-looking statements contained in this news release are forward-looking and not historical facts.
Some of the forward-looking statements may be identified by statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as “will likely result”, “are expected to”, “will continue”, “is anticipated”, “is targeting”, “estimated”, “intend”, “plan”, “projection”, “could”, “aim”, “vision”, “goals”, “objective”, “target”, “scheduled” and “outlook”). In particular, forward-looking statements in this news release include, but are not limited to, references to:
- with respect to the business, operations and results of the Company generally: general strategic plans and growth strategies; increase in funds from operations from the startup of a number of projects; the expected timing of completion of, and benefits of, the strategic combination with Cenovus; the expected timing of mailing the joint information circular to Husky and Cenovus shareholders; and the expected timing of the Husky and Cenovus special shareholder meetings;
- with respect to the Lloydminster Heavy Oil Value Chain, the expected timing of ramp-up to full capacity at Spruce Lake Central;
- with respect to U.S. Refining, expectations regarding the recovery of business and property damage insurance payments related to the Superior Refinery; and
- with respect to the Company’s Offshore business in Asia Pacific, the expected timing of first production and sales at Liuhua 29-1.
There are numerous uncertainties inherent in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary from production estimates.
Although the Company believes that the expectations reflected by the forward-looking statements presented in this news release are reasonable, the Company’s forward-looking statements have been based on assumptions and factors concerning future events that may prove to be inaccurate, including the ability to obtain regulatory approvals and meet other closing conditions to the business combination transaction with Cenovus, and the ability to integrate the Company’s and Cenovus’s businesses and operations and realize the corporate, operating and capital allocation synergies from the proposed transaction.
Those assumptions and factors are based on information currently available to the Company about itself and the businesses in which it operates. Information used in developing forward-looking statements has been acquired from various sources, including third-party consultants, suppliers and regulators, among others.
Because actual results or outcomes could differ materially from those expressed in any forward-looking statements, investors should not place undue reliance on any such forward-looking statements. By their nature, forward-looking statements involve numerous assumptions, inherent risks and uncertainties, both general and specific, which contribute to the possibility that the predicted outcomes will not occur. Some of these risks, uncertainties and other factors are similar to those faced by other oil and gas companies and some are unique to the Company.
The Company’s Annual Information Form for the year ended December 31, 2019, Management’s Discussion and Analysis for the three and nine months ended September 30, 2020 and other documents filed with securities regulatory authorities (accessible through the SEDAR website www.sedar.com and the EDGAR website www.sec.gov) describe some of the risks, material assumptions and other factors that could influence actual results and are incorporated herein by reference.
New factors emerge from time to time and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company’s course of action would depend upon management’s assessment of the future considering all information available to it at the relevant time. Any forward-looking statement speaks only as of the date on which such statement is made and, except as required by applicable securities laws, the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.
This news release contains references to the terms “funds from operations”, “free cash flow”, “net debt”, “operating margin”, and “net debt to trailing funds from operations”. None of these measures is used to enhance the Company’s reported financial performance or position. These measures are useful complementary measures in assessing the Company’s financial performance, efficiency and liquidity. With the exception of funds from operations, free cash flow and net debt, there are no comparable measures to these non-GAAP measures under IFRS.
Funds from operations is a non-GAAP measure which should not be considered an alternative to, or more meaningful than, cash flow – operating activities as determined in accordance with IFRS, as an indicator of financial performance. Funds from operations is presented in the Company’s financial reports to assist management and investors in analyzing operating performance of the Company in the stated period. Funds from operations equals cash flow – operating activities excluding change in non-cash working capital.
Free cash flow is a non-GAAP measure which should not be considered an alternative to, or more meaningful than, cash flow – operating activities as determined in accordance with IFRS, as an indicator of financial performance. Free cash flow is presented to assist management and investors in analyzing operating performance by the business in the stated period. Free cash flow equals funds from operations less capital expenditures.
The following table shows the reconciliation of net earnings to funds from operations and free cash flow, and related per share amounts, for the periods indicated:
|Three months ended||Six months ended|
|Sept. 30||June 30||Sept. 30||Sept. 30||Sept. 30|
|Items not affecting cash:|
|Depletion, depreciation, amortization and impairment||8,636||590||703||11,300||1,976|
|Inventory write-down to net realizable value||45||(362||)||-||45||-|
|Exploration and evaluation expenses||598||(2||)||-||596||23|
|Deferred income taxes||(2,030||)||(137||)||22||(2,751||)||(185||)|
|Foreign exchange loss (gain)||2||(1||)||(1||)||4||(15||)|
|Stock-based compensation expense (recovery)||(3||)||8||(9||)||(13||)||11|
|Gain on sale of assets||(9||)||(2||)||(3||)||(17||)||(5||)|
|Unrealized mark to market loss (gain)||(19||)||96||4||(14||)||57|
|Share of equity investment income (loss)||1||10||(19||)||1||(64||)|
|Gain on insurance recoveries for damage to property||-||-||(13||)||-||(13||)|
|Settlement of asset retirement obligations||(3||)||(3||)||(73||)||(30||)||(186||)|
|Distribution from equity investment||17||134||113||167||160|
|Change in non-cash working capital||(69||)||(28||)||(221||)||233||(677||)|
|Cash flow - operating activities||79||(10||)||800||424||2,105|
|Change in non-cash working capital||69||28||221||(233||)||677|
|Funds from operations||148||18||1,021||191||2,782|
|Free cash flow||(206||)||(292||)||153||(1,085||)||244|
|Weighted average number of common shares outstanding||1,005.1||1,005.1||1,005.1||1,005.1||1,005.1|
|Funds from operations|
|Per common share - Basic ($/share)||0.15||0.02||0.19||1.02||2.77|
Net debt is a non-GAAP measure that equals the sum of long-term debt, long-term debt due within one year and short-term debt, less cash and cash equivalents. Net debt is considered to be a useful measure in assisting management and investors to evaluate the Company’s financial strength.
The following table shows the reconciliation of net debt as at the dates indicated:
|Sept. 30||June 30||Sept. 30|
|Long-term debt due within one year||500||-||-|
|Cash and cash equivalents||(1,028||)||(633||)||(1,322||)|
Operating margin is a non-GAAP measure which should not be considered an alternative to, or more meaningful than, “revenue, net of royalties” as determined in accordance with IFRS, as an indicator of financial performance. Operating margin is presented to assist management and investors in analyzing operating performance of the Company in the stated period. Operating margin equals revenues net of royalties less purchases of crude oil and products, production, operating and transportation expenses, and selling general and administrative expenses.
The following table shows the reconciliation of operating margin for the periods indicated:
|Three months ended|
|Sept. 30, 2020||June 30, 2020|
|($ millions)||Integrated Corridor||Offshore||Corporate||Total||Integrated Corridor||Offshore||Corporate||Total|
|Revenue, net of royalties||3,033||293||-||3,326||5,721||725||-||6,446|
|Purchases of crude oil and products||2,276||(37||)||-||2,239||4,688||32||-||4,720|
|Production and operating expenses||555||75||-||630||1,153||134||-||1,287|
|Selling, general and administrative expenses||91||16||73||180||217||41||111||369|
|Three months ended|
|Sept. 30, 2019|
|($ millions)||Integrated Corridor||Offshore||Corporate||Total|
|Revenue, net of royalties||4,921||371||-||5,292|
|Purchases of crude oil and products||3,481||4||-||3,485|
|Production and operating expenses||641||86||-||727|
|Selling, general and administrative expenses||93||14||42||149|
|Nine months ended|
|Sept. 30, 2020||Sept. 30, 2019|
|($ millions)||Integrated Corridor||Offshore||Corporate||Total||Integrated Corridor||Offshore||Corporate||Total|
|Revenue, net of royalties||8,754||1,018||-||9,772||14,058||1,011||-||15,069|
|Purchases of crude oil and products||6,964||(5||)||-||6,959||9,554||2||-||9,556|
|Production and operating expenses||1,708||209||-||1,917||1,981||251||-||2,232|
|Selling, general and administrative expenses||308||57||184||549||263||44||170||477|
Operating margins and operating costs per boe have been calculated on a sales volume basis.
Net debt to trailing funds from operations is a non-GAAP measure that equals net debt divided by the 12-month trailing funds from operations as at September 30, 2020. Net debt to trailing funds from operations is considered to be a useful measure in assisting management and investors to evaluate the Company’s financial strength.
DISCLOSURE OF OIL AND GAS INFORMATION
Unless otherwise indicated: (i) projected and historical production volumes provided are gross, which represents the total or the Company’s working interest share, as applicable, before deduction of royalties; and (ii) all Husky working interest production volumes quoted are before deduction of royalties.
The Company uses the term “barrels of oil equivalent” (or “boe”), which is consistent with other oil and gas companies’ disclosures, and is calculated on an energy equivalence basis applicable at the burner tip whereby one barrel of crude oil is equivalent to six thousand cubic feet of natural gas. The term boe is used to express the sum of the total company products in one unit that can be used for comparisons. Readers are cautioned that the term boe may be misleading, particularly if used in isolation. This measure is used for consistency with other oil and gas companies and does not represent value equivalency at the wellhead.
The following table provides the full product breakdown for Integrated Corridor and Offshore upstream production, before royalties, for the periods indicated:
|Three Months Ended||Six Months Ended|
|Upstream production, before royalties|
|Light crude oil & medium (mbbls/day)||21||26||31||25||22|
|Heavy crude oil (mbbls/day)||18||17||32||22||29|
|Natural gas liquids (mbbls/day)||22||22||22||21||23|
|Conventional natural gas (mmcf/day)||479||522||503||496||498|
|Total equivalent production (mboe/day)||258||247||295||268||283|
All currency is expressed in Canadian dollars unless otherwise indicated.