All financial figures are in Canadian dollars ($ or C$) and all references to barrels are per barrel of bitumen unless otherwise noted
CALGARY, AB, March 3, 2021 /CNW/ – MEG Energy Corp. (TSX: MEG) (“MEG” or the “Corporation”) reported its full year 2020 operational and financial results.
MEG Energy announces full year 2020 free cash flow of $129 million, debt repayment of $132 million and 28% year-over-year reduction in G&A expense (CNW Group/MEG Energy Corp.)
- Free cash flow of $129 million driven by adjusted funds flow of $278 million ($0.91 per share) and disciplined capital spend of $149 million;
- Bitumen production volumes of 82,441 barrels per day (bbls/d) at a steam-oil ratio (SOR) of 2.3;
- Repayment of $132 million of long-term debt concurrent with the refinancing of US$1.2 billion of existing indebtedness;
- General and administrative expense of $49 million which was $19 million, or 28%, lower than 2019;
- Net operating costs of $6.18 per barrel, supported by record low non-energy operating costs of $4.38 per barrel and strong power sales which offset 45% of per barrel energy operating costs resulting in a net energy operating cost of $1.80 per barrel; and
- Exited 2020 with $114 million of cash on hand and MEG’s $800 million modified covenant-lite revolver remains undrawn.
“Notwithstanding the incredibly challenging environment our industry faced in 2020, MEG continued to execute on its strategic focus of improving overall cost efficiencies, preserving financial liquidity and enhancing MEG’s competitive position,” says Derek Evans, President and Chief Executive Officer. “In keeping with this strategy, we significantly reduced G&A, repaid indebtedness, extended the maturity runway of outstanding long-term debt and began moving the majority of our barrels to the USGC for the first time. None of this would have been achieved without the commitment, perseverance, and resilience of the MEG team which has my thanks and those of the Board for all their collective and individual efforts during the year.”
Financial Liquidity and Debt Repayment
In the last three years, the Corporation has repaid approximately $2 billion (US$1.5 billion) of long-term debt including $132 million (US$100 million) in 2020.
In January 2020, the Corporation successfully closed a private offering of US$1.2 billion in aggregate principal amount of 7.125% senior unsecured notes due February 2027. The net proceeds of the offering plus cash on hand were used to fully redeem US$800 million of the 6.375% senior unsecured notes due January 2023 and partially redeem US$400 million of the US$1.0 billion 7.0% senior unsecured notes due March 2024. Post this refinancing, MEG had a 4-year runway until its next debt maturity represented by the remaining US$600 million of March 2024 notes.
Subsequent to year end, in February 2021, the Corporation successfully closed a private offering of US$600 million in aggregate principal amount of 5.875% senior unsecured notes due February 2029. The net proceeds of the offering plus cash on hand were used to fully redeem the remaining US$600 million of the 7.0% senior unsecured notes due March 2024. Post this refinancing, MEG maintains a 4-year runway until its next debt maturity represented by the remaining US$496 million of 6.50% second lien notes due January 2025.
MEG generated $129 million of free cash flow in 2020 and exited the year with $114 million of cash on hand. The Corporation’s $800 million modified covenant-lite revolver, in place until July 2024, remains undrawn.
Blend Sales Pricing and North American Market Access
MEG realized an average AWB blend sales price of US$28.07 per barrel in 2020 compared to US$46.19 per barrel in 2019. The decrease in average AWB blend sales price year over year was primarily a result of the average WTI price decreasing by US$17.63 per barrel. MEG sold 40% of its sales volumes to the US Gulf Coast (“USGC”) in 2020 compared to 33% in 2019. The increase in sales to the USGC in 2020 is primarily a result of the Corporation’s increased contracted blend transportation capacity on the Flanagan South and Seaway Pipeline systems (“FSP”) effective July 1, 2020 from 50,000 bbls/d to 100,000 bbls/d.
Transportation and storage costs averaged US$6.74 per barrel of AWB blend sales in 2020 compared to US$5.70 per barrel of AWB blend sales 2019. The increase in transportation and storage costs is primarily due to the fixed costs associated with increased FSP contracted capacity coupled with lower year over year sales volumes. MEG’s AWB blend sales by rail were 16,865 bbls/d in 2020, representing 14% of total blend sales, compared to 19,686 bbls/d, representing 15% of total blend sales in 2019. MEG is not anticipating undertaking any AWB blend sales by rail in 2021.
Bitumen production averaged 82,441 bbls/d in 2020, compared to 93,082 bbls/d in 2019. Contributing to the decrease was the impact of the Corporation’s major planned turnaround at the Phase 1 and 2 facilities which was extended in duration to 75-days and expanded in scope relative to the Corporation’s original budget in order to minimize staff levels at site during COVID-19 and maximize utilization of the Corporation’s internal resources thereby lowering overall cash costs. MEG also made the decision to advance turnaround activities from 2021 to significantly reduce the 2021 turnaround requirements.
The decrease in 2020 bitumen production was also impacted by the Corporation’s decision, in the first half of 2020, to reduce capital investment by $100 million and undertake voluntary price-related production curtailments during the second quarter of 2020 in order to preserve financial liquidity.
Non-energy operating costs were $133 million, or $4.38 per barrel, in 2020 compared to $157 million, or $4.61 per barrel, in 2019. General and administrative expense was $49 million, or $1.62 per barrel, in 2020 compared to $68 million, or $1.99 per barrel, in 2019. Throughout 2020 MEG continued efforts to drive efficiency into its cost structure including reductions in staffing levels as well as temporary salary rollbacks and vendor concessions which contributed to the decrease in expenses year over year. The Corporation also took part in various government led initiatives during 2020, aimed at supporting businesses facing the negative impacts of COVID-19.
Adjusted Funds Flow and Net Loss
The Corporation’s adjusted funds flow was $278 million in 2020 compared to $726 million in 2019. The decrease in adjusted funds flow was driven primarily by the 31% decrease in the WTI price year over year partially offset by a realized commodity risk management gain of $343 million.
The Corporation recognized a net loss of $357 million in 2020 compared to a net loss of $62 million in 2019. The increase in the net loss year over year was largely driven by significant non-cash items including a $366 million exploration expense associated with certain non-core assets and a decrease in the unrealized foreign exchange gain driven by the strengthening of the Canadian dollar. These were partially offset by an unrealized commodity risk management gain as a result of weaker forward commodity prices compared to an unrealized commodity risk management loss in the same period of 2019.
Capital expenditures in 2020 totaled $149 million compared to $198 million in 2019. The decrease in capital spending in 2020, compared to 2019, reflects the Corporation’s decision to reduce its original 2020 capital budget of $250 million by approximately $100 million due to the unprecedented negative macro oil price environment experienced in 2020. Capital expenditures during 2020 primarily consisted of sustaining and maintenance and turnaround activities.
In 2020 we continued to advance our Environmental, Social and Governance (“ESG”) activities and strategy with corporate commitments to supporting the Paris Agreement, the approval of our long-term ambition of reaching net-zero GHG emissions (scope 1 and scope 2) by 2050, and our commitment to human rights as reflected in the UN Universal Declaration of Human Rights.
We remain committed to ESG leadership and look forward to updating our performance in that regard with the release of our 2020 Sustainability Report mid-2021.
COVID-19 Global Pandemic
The health and safety of its people is the Corporation’s first priority. The Corporation’s business activities have been declared an essential service by the Alberta Government and the Corporation remains committed to ensuring the health and safety of all its personnel and business partners, and the safe and reliable operation of the Christina Lake facility. At the onset of the global pandemic, a COVID-19 task force was established by the Corporation comprised of members of senior management and employees as well as third party expert consultants to promptly implement measures to protect the health and safety of the Corporation’s work force and the public, as well as to ensure continuity of operations. The implementation of mandatory self-quarantine policies, travel restrictions, screening protocols, enhanced cleaning and sanitation measures, and social distancing measures, including directing the vast majority of its office staff and certain non-essential field staff to work from home at the onset of the pandemic in March 2020, revising shift schedules and increasing appropriate protective equipment, were proactively established. To date, the Corporation has not experienced any COVID-19 outbreaks at any of its locations.
The Corporation continues to monitor the developing COVID-19 situation to determine what, if any, additional measures might need to be taken to ensure that the health and safety of its people remain a top priority. In September, MEG safely returned to near-normal operations, with new safety measures in place, including the majority of staff returning to regular work locations. In December 2020, the Corporation reverted to having staff who are able to work remotely to do so, to reduce risk of exposure. Flexibility and adaptability continue to be integral to the risk management strategy.
Announced December 7, 2020, MEG’s capital investment plan for 2021 of $260 million includes $245 million to be directed towards sustaining and maintenance capital and the remaining $15 million directed towards non-discretionary field infrastructure, regulatory and corporate capital costs.
MEG’s 2021 annual average bitumen production volumes are targeted to be in the range of 86,000 – 90,000 bbls/d and the Corporation’s 2021 non-energy operating costs and general and administrative expense are targeted to be in the range of $4.60 – $5.00 per barrel and $1.70 – $1.80 per barrel, respectively.
2021 Commodity Price Risk Management
To support MEG’s 2021 capital budget announced December 7, 2020, MEG entered into benchmark WTI fixed price hedges and enhanced WTI fixed price hedges with sold put options for approximately 47% (60% 1H, 33% 2H) of forecast bitumen production at an average price of US$46.66 per barrel. These hedges were put in place to protect funding of the Corporation’s 2021 capital program with internally generated cash flow down to a US$30 per barrel WCS price and to protect MEG’s balance sheet. The first half weighting of these hedges reflect the first half weighting of MEG’s capital investment profile as well as the uncertainty regarding pace of 2021 economic recovery at time of execution.
MEG has hedged approximately 23% of its forecast Edmonton WTI:WCS differential exposure (41% 1H, 5% 2H) at an average differential of US$13.42 per barrel. MEG has also hedged approximately 40% of its expected 2021 condensate requirements at a landed-at-Edmonton price of 96% of WTI, approximately 35% of expected 2021 natural gas requirements at an average price of C$2.62 per GJ and fixed the sales price on approximately 25% of expected 2021 power available for sale at an average price of C$62.80 per MW. The table below reflects MEG’s 2021 hedge positions.
|Q1 2021||Q2 2021||Q3 2021||Q4 2021||2021|
|WTI Fixed Price Hedges|
|Weighted average fixed WTI price (US$/bbl)||$||48.28||$||46.31||$||—||$||—||$||47.77|
|Enhanced WTI Fixed Price Hedges with Sold Put Options(1)|
|Weighted average fixed WTI price (US$/bbl) /||$ 46.18 /||$ 46.18 /||$ 46.18 /||$ 46.18 /||$ 46.18 /|
|Put option strike price (US$/bbl)||$38.79||$38.79||$38.79||$38.79||$38.79|
|WTI:WCS Differential Hedges|
|Weighted average fixed WTI:WCS differential (US$/bbl)||$||(14.44)||$||(13.27)||$||(11.18)||$||—||$||(13.42)|
|Weighted average % of WTI landed in Edmonton (%)(4)||96%||97%||96%||96%||96%|
|Natural Gas Hedges|
|Weighted average fixed AECO price (C$/GJ)||$||2.64||$||2.61||$||2.61||$||2.61||$||2.62|
|Weighted average fixed price (C$/MW)||$||63.06||$||62.75||$||62.75||$||62.75||$||62.80|
|(1)||If in any month of 2021 the month average WTI settlement price is US$38.79 per barrel (the sold put option) or better, MEG will receive US$46.18 per barrel (the fixed price swap) on each barrel hedged in that month. If in any month of 2021 the month average WTI settlement price is less than US$38.79 per barrel, MEG will receive the month average WTI settlement price in that month plus US$7.39 per barrel (the swap spread) on each barrel hedged in that month.|
|(2)||Includes 9,833 bbls/d (Q1) and 15,000 bbls/d (Q2) of physical forward blend sales at fixed WTI:AWB differentials.|
|(3)||Includes approximately 4,500 bbls/d of physical forward condensate purchases for the full year 2021 (annual average).|
|(4)||The average % of WTI landed in Edmonton includes estimated net transportation costs to Edmonton.|
|(5)||Includes 7,466 GJ/d of physical forward natural gas purchases for the full year 2021 (annual average) at a fixed AECO price.|
|(6)||Represents physical forward power sales at a fixed power price.|
A conference call will be held to review MEG’s full-year 2020 operating and financial results at 6:30 a.m. Mountain Time (8:30 a.m. Eastern Time) on Thursday, March 4th, 2021. To participate, please dial the North American toll-free number 1-888-390-0546, or the international call number 1-416-764-8688.
A recording of the call will be available by 12 noon Mountain Time (2 p.m. Eastern Time) on the same day at www.megenergy.com/investors/presentations-and-events.
Operational and Financial Highlights
|Three months ended December 31||Year ended December 31|
|($millions, except as indicated)||2020||2019||2020||2019|
|Bitumen production – bbls/d||91,030||94,566||82,441||93,082|
|Bitumen sales – bbls/d||95,731||94,347||82,722||93,587|
|Bitumen realization – $/bbl||38.64||46.86||27.23||53.21|
|Net operating costs – $/bbl(1)||6.98||5.87||6.18||5.24|
|Non-energy operating costs – $/bbl||4.70||4.49||4.38||4.61|
|Cash operating netback – $/bbl(2)||18.66||28.33||19.22||32.15|
|Adjusted funds flow(3)||84||157||278||726|
|Per share, diluted||0.27||0.51||0.91||2.41|
|Net earnings (loss)||16||26||(357)||(62)|
|Per share, diluted||0.05||0.09||(1.18)||(0.21)|
|Cash and cash equivalents||114||206||114||206|
|Long-term debt – C$||2,912||3,123||2,912||3,123|
|Long-term debt – US$||2,283||2,409||2,283||2,409|
|(1)||Net operating costs include energy and non-energy operating costs, reduced by power revenue.|
|(2)||Cash operating netback is a non-GAAP measure and does not have a standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures used by other companies.|
|(3)||Refer to Note 26 of the 2020 audited annual consolidated financial statements for further details.|
Basis of Presentation
MEG prepares its financial statements in accordance with International Financial Reporting Standards (“IFRS”) and presents financial results in Canadian dollars ($ or C$), which is the Corporation’s functional currency.
Certain financial measures in this news release including free cash flow and cash operating netback are non-GAAP measures. These terms are not defined by IFRS and, therefore, may not be comparable to similar measures provided by other companies. These non-GAAP financial measures should not be considered in isolation or as an alternative for measures of performance prepared in accordance with IFRS.
Free Cash Flow
Free cash flow is presented to assist management and investors in analyzing performance by the Corporation as a measure of financial liquidity and the capacity of the business to repay debt. Free cash flow is calculated as adjusted funds flow less capital expenditures.
|Three months ended
|Net cash provided by (used in) operating activities||$||115||$||225||$||302||$||631|
|Net change in non-cash operating working capital items||(34)||(52)||(63)||110|
|Funds flow from operations||81||173||239||741|
|Net change in other liabilities(2)||3||3||3||3|
|Adjusted funds flow||$||84||$||157||$||278||$||726|
|Free cash flow||$||44||$||85||$||129||$||528|
|(1)||During 2020 these costs were incurred to mitigate rail sales contract exposure. The economic decision to divert sales volumes from rail contracts at Edmonton to the USGC more than recovered the cost of contract cancellations. During the fourth quarter of 2019, the Corporation agreed to relieve the Alberta Petroleum Marketing Commission of all obligations pursuant to a crude oil purchase and sale agreement in exchange for a payment of $20 million. Contract cancellation costs or recoveries are excluded from adjusted funds flow as they are not considered part of ordinary continuing operating results.|
|(2)||Includes the change in liability associated with the termination of a long-term transportation contract that was previously expensed.|
Cash Operating Netback
Cash operating netback is a non-GAAP measure widely used in the oil and gas industry as a supplemental measure of a company’s efficiency and its ability to fund future capital expenditures. The Corporation’s cash operating netback is calculated by deducting the related cost of diluent, blend purchases, transportation and storage, third-party curtailment credits, operating expenses, royalties and realized commodity risk management gains or losses from blend sales and power revenue. The per barrel calculation of cash operating netback is based on bitumen sales volume.
Certain statements contained in this news release may constitute forward-looking statements within the meaning of applicable Canadian securities laws. These statements relate to future events or MEG’s future performance. All statements other than statements of historical fact may be forward-looking statements. The use of any of the words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “should”, “believe”, “plan”, “intend”, “target”, “potential” and similar expressions are intended to identify forward-looking statements.
Forward-looking statements are often, but not always, identified by such words. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. In particular, and without limiting the foregoing, this press release contains forward looking statements with respect to: the Corporation’s expectations regarding 2021 AWB blend sales; the impact of the major turnaround at the Christina Lake facility, including the impact on 2021 turnaround requirements; the Corporation’s ongoing financial liquidity; the Corporation’s ESG commitments; the Corporation’s actions taken to respond to safety and financial challenges associated with the COVID-19 pandemic; the Corporation’s commitment to ensuring the health and safety of its personnel and safe and reliable operations of the Christina Lake facility; all statements relating to the Corporation’s full year 2021 guidance, including full year 2021 production, non-energy operating costs, general and administrative expenses and capital expenditures; the Corporation’s expectations regarding its 2021 capital budget, including the expected level of internally generated cash flow in 2021 and the Corporation’s mitigation strategies to protect its 2021 capital program and balance sheet against downward commodity price volatility; and all statements relating to the Corporation’s 2021 hedge book.
Forward-looking information contained in this press release is based on management’s expectations and assumptions regarding, among other things: future crude oil, bitumen blend, natural gas, electricity, condensate and other diluent prices, differentials, the level of apportionment on the Enbridge mainline system, foreign exchange rates and interest rates; the recoverability of MEG’s reserves and contingent resources; MEG’s ability to produce and market production of bitumen blend successfully to customers; future growth, results of operations and production levels; future capital and other expenditures; revenues, expenses and cash flow; operating costs; reliability; continued liquidity and runway to sustain operations through a prolonged market downturn; MEG’s ability to reduce or increase production to desired levels, including without negative impacts to its assets; anticipated reductions in operating costs as a result of optimization and scalability of certain operations; anticipated sources of funding for operations and capital investments; plans for and results of drilling activity; the regulatory framework governing royalties, land use, taxes and environmental matters, including the timing and level of government production curtailment and federal and provincial climate change policies, in which MEG conducts and will conduct its business; the impact of MEG’s response to the COVID-19 global pandemic; and business prospects and opportunities. By its nature, such forward-looking information involves significant known and unknown risks and uncertainties, which could cause actual results to differ materially from those anticipated.
These risks and uncertainties include, but are not limited to, risks and uncertainties related to: the oil and gas industry, for example, the securing of adequate access to markets and transportation infrastructure (including pipelines and rail) and the commitments therein; the availability of capacity on the electricity transmission grid; the uncertainty of reserve and resource estimates; the uncertainty of estimates and projections relating to production, costs and revenues; health, safety and environmental risks, including public health crises, such as the COVID-19 pandemic, and any related actions taken by governments and businesses; legislative and regulatory changes to, amongst other things, tax, land use, royalty and environmental laws and production curtailment; the cost of compliance with current and future environmental laws, including climate change laws; risks relating to increased activism and public opposition to fossil fuels and oil sands; assumptions regarding and the volatility of commodity prices, interest rates and foreign exchange rates; commodity price, interest rate and foreign exchange rate swap contracts and/or derivative financial instruments that MEG may enter into from time to time to manage its risk related to such prices and rates; timing of completion, commissioning, and start-up, of MEG’s turnarounds; the operational risks and delays in the development, exploration, production, and the capacities and performance associated with MEG’s projects; MEG’s ability to reduce or increase production to desired levels, including without negative impacts to its assets; MEG’s ability to finance sustaining capital expenditures; MEG’s ability to maintain sufficient liquidity to sustain operations through a prolonged market downturn; changes in credit ratings applicable to MEG or any of its securities; MEG’s response to the COVID-19 global pandemic; the severity and duration of the COVID-19 pandemic; the potential for a temporary suspension of operations impacted by an outbreak of COVID-19; and changes in general economic, market and business conditions.
Although MEG believes that the assumptions used in such forward-looking information are reasonable, there can be no assurance that such assumptions will be correct. Accordingly, readers are cautioned that the actual results achieved may vary from the forward-looking information provided herein and that the variations may be material. Readers are also cautioned that the foregoing list of assumptions, risks and factors is not exhaustive.
Further information regarding the assumptions and risks inherent in the making of forward-looking statements can be found in MEG’s most recently filed Annual Information Form (“AIF”), along with MEG’s other public disclosure documents. Copies of the AIF and MEG’s other public disclosure documents are available through the Company’s website at www.megenergy.com/investors and through the SEDAR website at www.sedar.com.
The forward-looking information included in this news release is expressly qualified in its entirety by the foregoing cautionary statements. Unless otherwise stated, the forward-looking information included in this news release is made as of the date of this news release and MEG assumes no obligation to update or revise any forward-looking information to reflect new events or circumstances, except as required by law.
This news release contains future-oriented financial information and financial outlook information (collectively, “FOFI”) about MEG’s prospective results of operations including, without limitation, the Corporation’s hedging program, capital expenditures, production, operating costs and general and administrative costs, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth above. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on FOFI. MEG’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these FOFI, or if any of them do so, what benefits MEG will derive therefrom. MEG has included the FOFI in order to provide readers with a more complete perspective on MEG’s future operations and such information may not be appropriate for other purposes. MEG disclaims any intention or obligation to update or revise any FOFI statements, whether as a result of new information, future events or otherwise, except as required by law. MEG’s 2020 Annual Management’s Discussion and Analysis (“MD&A”) and 2020 Annual Consolidated Financial Statements are available at www.megenergy.com/investors and at www.sedar.com.
MEG is an energy company focused on sustainable in situ thermal oil production in the southern Athabasca oil region of Alberta, Canada. MEG is actively developing innovative enhanced oil recovery projects that utilize steam-assisted gravity drainage (“SAGD”) extraction methods to improve the responsible economic recovery of oil as well as lower carbon emissions. MEG transports and sells its thermal oil (AWB) to customers throughout North America and internationally.
Learn more at: www.megenergy.com
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SOURCE MEG Energy Corp.