All financial figures are in Canadian dollars ($ or C$) and all references to barrels are per barrel of bitumen unless otherwise noted
CALGARY, AB, May 3, 2021 /CNW/ - MEG Energy Corp. (TSX: MEG) ("MEG" or the "Corporation") reported its first quarter of 2021 operational and financial results.
MEG continues to proactively respond to the safety challenges associated with the COVID–19 pandemic and remains committed to ensuring the health and safety of all of its personnel and the safe and reliable operation of the Christina Lake facility.
"MEG's first quarter was strong from both a financial and operational perspective" said Derek Evans, President and Chief Executive Officer. "We continue to benefit from both the strength in global oil market dynamics as well as the structural improvement in heavy oil differentials. Operationally, better than expected Christina Lake reservoir performance post the 75-day turnaround in 2020 has given us the confidence to tighten our production guidance and sets us up well for the balance of 2021."
First quarter financial and operating highlights include:
- Adjusted funds flow of $127 million ($0.41 per share), impacted by a realized commodity price risk management loss in the quarter of $69 million ($0.22 per share);
- Quarterly production volumes of 90,842 barrels per day (bbls/d) at a steam–oil ratio (SOR) of 2.37. Annual average production guidance has been revised to 88,000 – 90,000 bbls/d as production has continued to outpace expectations post the major turnaround in 2020;
- Net operating costs of $5.25 per barrel, including non–energy operating costs of $4.05 per barrel. Power revenue offset energy operating costs by 72%, resulting in a net impact of $1.20 per barrel;
- Successfully refinanced in the quarter US$600 million of existing indebtedness at a coupon of 5.875% due February 2029, which pushed out the earliest outstanding long term debt maturity to 2025; and
- Total capital investment of $70 million in the quarter was directed to sustaining and maintenance capital, resulting in $57 million of free cash flow in the quarter.
Blend Sales Pricing and North American Market Access
MEG realized an average AWB blend sales price of US$48.39 per barrel during the first quarter of 2021 compared to US$35.11 per barrel in the fourth quarter of 2020. The increase in average AWB blend sales price quarter over quarter was primarily a result of the average WTI price increasing by US$15.18 per barrel, partially offset by the average WTI:AWB differential at Edmonton widening by US$3.66 per barrel. MEG sold 38% of its sales volumes to the U.S. Gulf Coast ("USGC") in the first quarter of 2021 compared to 48% in the fourth quarter of 2020. The decrease in sales volume to the USGC in the first quarter of 2021 is a result of the Enbridge mainline apportionment increasing from 22% in the fourth quarter of 2020 to 48% in the first quarter of 2021.
Transportation and storage costs averaged US$6.13 per barrel of AWB blend sales in the first quarter of 2021 compared to US$7.59 per barrel of AWB blend sales in the fourth quarter of 2020. The decrease in transportation and storage costs is primarily due to less volumes shipped to the USGC and no FOB rail sales.
Bitumen production averaged 90,842 bbls/d in the first quarter of 2021, consistent with average bitumen production of 91,030 bbls/d in the fourth quarter of 2020.
Non–energy operating costs averaged $4.05 per barrel of bitumen sales in the first quarter of 2021 compared to $4.70 per barrel in the fourth quarter of 2020. Energy operating costs, net of power revenue, averaged $1.20 per barrel in the first quarter of 2021 compared to $2.28 per barrel in the fourth quarter of 2020. MEG benefited from strong power prices on power sales from its cogeneration facilities whereby power revenue offset energy operating costs by 72% during the first quarter of 2021.
General & administrative expense ("G&A") was $14 million, or $1.77 per barrel of production, in the first quarter of 2021 compared to $14 million, or $1.65 per barrel of production, in the fourth quarter of 2020. The difference in per barrel G&A cost was due to lower production in the first quarter of 2021 compared to the fourth quarter of 2020.
Adjusted Funds Flow and Net Loss
MEG's bitumen realization averaged $52.34 per barrel in the first quarter of 2021 compared to $38.64 per barrel in the fourth quarter of 2020. The increase in average bitumen realization was due to the higher WTI price quarter over quarter. Offsetting the increase in bitumen realization during the first quarter of 2021, compared to the fourth quarter of 2020, was a realized commodity risk management loss of $8.80 per barrel in the first quarter of 2021 compared to a realized commodity risk management gain of $1.31 per barrel in the fourth quarter of 2020. This reflects stronger WTI settlement prices compared to WTI fixed price contracts in place.
The Corporation's cash operating netback averaged $26.03 per barrel in the first quarter of 2021 compared to $18.66 per barrel in the fourth quarter of 2020. The increased cash operating netback drove the increase in the Corporation's adjusted funds flow from $84 million in the fourth quarter of 2020 to $127 million in the first quarter of 2021.
The Corporation recognized a net loss of $17 million in the first quarter of 2021 compared to net earnings of $16 million in the fourth quarter of 2020. This change was primarily the result of a decreased unrealized gain on foreign exchange partially offset by the increased cash operating netback.
MEG invested $70 million in the first quarter of 2021 compared to $40 million in the fourth quarter of 2020, which was primarily directed towards sustaining and maintenance activities.
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 $57 million of free cash flow in the first quarter of 2021 and exited the quarter with $54 million of cash on hand. The Corporation's $800 million modified covenant-lite revolver, in place until July 2024, remains undrawn.
COVID-19 Global Pandemic
The Corporation continues to proactively respond to the safety challenges associated with COVID–19 and 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. The screening procedures and protocols implemented by the Corporation's COVID–19 task force during the first quarter of 2020 continue to be enhanced to ensure continued safe and reliable operations. Flexibility and adaptability continue to be integral to the Corporation's response to the pandemic. 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.
Based on better than expected production performance in the first quarter, MEG is revising its full year 2021 average production from 86,000 – 90,000 bbls/d to 88,000 – 90,000 bbls/d.
Due to increased apportionment on the Enbridge mainline, MEG is revising downward its expected sales into the U.S. Gulf coast via Flanagan South and Seaway Pipeline systems ("FSP") from approximately two-thirds of its full year 2021 AWB blend sales volumes to approximately 50%. As a result, MEG is revising downward its estimate of full year 2021 total transportation costs from US$7.75 to US$8.25 per barrel of AWB blend sales to US$6.75 to US$7.25 per barrel of AWB blend sales.
Summary of 2021 Guidance
2021 Revised Guidance
2021 Original Guidance
Bitumen production - annual average
88,000 - 90,000 bbls/d
86,000 - 90,000 bbls/d
Non-energy operating costs
$4.60 - $5.00 per bbl
$4.60 - $5.00 per bbl
$1.70 - $1.80 per bbl
$1.70 - $1.80 per bbl
2021 Commodity Price Risk Management
For the last nine months of 2021, MEG has entered into benchmark WTI fixed price hedges and enhanced WTI fixed price hedges with sold put options for approximately 37% of forecast bitumen production at an average price of US$46.20 per barrel. MEG has also hedged approximately 25% of its forecast Edmonton WTI:WCS differential exposure at an average differential of US$12.82 per barrel. MEG has also hedged approximately 40% of its expected 2021 condensate requirements at a landed-at-Edmonton price of 97% 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$62.80 per MWh. The table below reflects MEG's 2021 hedge positions.
WTI Fixed Price Hedges
Weighted average fixed WTI price (US$/bbl)
Enhanced WTI Fixed Price Hedges with Sold Put Options(1)
Weighted average fixed WTI price (US$/bbl) / Put option strike price (US$/bbl)
$ 46.18 /
$ 46.18 /
$ 46.18 /
WTI:WCS Differential Hedges
Weighted average fixed WTI:WCS differential (US$/bbl)
Weighted average % of WTI landed in Edmonton (%)(4)
Natural Gas Hedges
Weighted average fixed AECO price (C$/GJ)
Weighted average fixed price (C$/MWh)
If in any month the 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 the 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$7.39 per barrel (the swap spread) on each barrel hedged in that month.
Includes 15,000 bbls/d of physical forward blend sales in Q2 at fixed WTI:AWB differentials.
Includes approximately 4,500 bbls/d of physical forward condensate purchases for Q2 to Q4 (average).
The average % of WTI landed in Edmonton includes estimated net transportation costs to Edmonton.
Includes 5,000 GJ/d of physical forward natural gas purchases for the Q2 to Q4 at a fixed AECO price.
Represents physical forward power sales at a fixed power price.
A conference call will be held to review MEG's first quarter of 2021 operating and financial results at 6:30 a.m. Mountain Time (8:30 a.m. Eastern Time) on Tuesday, May 4th, 2021. To participate, please dial the North American toll-free number 1-888-390-0546, or the international call number 1-416-764-8688.
A recording of the call will be available by 12 noon Mountain Time (2 p.m. Eastern Time) on the same day at www.megenergy.com/investors/presentations-and-events.
Operational and Financial Highlights
($millions, except as indicated)
Bitumen production - bbls/d
Bitumen sales - bbls/d
Bitumen realization - $/bbl
Net operating costs - $/bbl(1)
Non-energy operating costs - $/bbl
Cash operating netback - $/bbl(2)
General & administrative expense - $/bbl(3)
Adjusted funds flow(4)
Per share, diluted
Net earnings (loss)
Per share, diluted
Cash and cash equivalents
Long-term debt - C$
Long-term debt - US$
Net operating costs include energy and non-energy operating costs, reduced by power revenue.
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. Refer to the "NON-GAAP MEASURES" section of this Press Release.
General and administrative expense ("G&A") per barrel is based on bitumen production volumes.
Refer to Note 17 of the March 31, 2021 interim 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 March 31
Net cash provided by (used in) operating activities
Net change in non-cash operating working capital items
Funds flow from operations
Payments on onerous contracts
Adjusted funds flow
Free cash flow
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 actions to ensuring the health and safety of its personnel and safe and reliable operations of the Christina Lake facility; the performance of the Corporation's reservoir performance post the 2020 75-day turnaround; 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 full year 2021 sales into the USGC; the Corporation's expectations regarding full 2021 total transportation costs; 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.
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