All financial figures are in Canadian dollars ($ or C$) and all references to barrels are per barrel of bitumen unless otherwise noted
CALGARY, AB, July 22, 2021 /CNW/ – MEG Energy Corp. (TSX: MEG) (“MEG” or the “Corporation”) reported its second 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 Energy Q2 2021 Results Press Release (CNW Group/MEG Energy Corp.)
“The second quarter was another strong operational quarter for MEG, giving us the confidence to increase our full year 2021 production guidance and begin the work to bring our Christina Lake facility back up to full operational utilization and re-initiate debt reduction” said Derek Evans, President and Chief Executive Officer. “Today we announced the redemption of approximately $125 million of debt and are committed to applying all free cash flow generated in the second half of 2021 to debt reduction.”
Second quarter financial and operating highlights include:
- Adjusted funds flow of $166 million ($0.53 per share), impacted by a realized commodity price risk management loss in the quarter of $87 million ($0.28 per share);
- Quarterly production volumes of 91,803 barrels per day (bbls/d) at a steam–oil ratio (SOR) of 2.39. Based on strong operational performance, annual average production guidance has been upwardly revised from 88,000 – 90,000 bbls/d to 91,000 – 93,000 bbls/d;
- Net operating costs of $5.54 per barrel, including non–energy operating costs of $3.84 per barrel. Power revenue offset energy operating costs by 60%, resulting in a net impact of $1.70 per barrel;
- Sale of non-core industrial lands near Edmonton for cash proceeds of approximately $44 million;
- Total capital investment of $70 million in the quarter was directed to sustaining and maintenance capital, resulting in $96 million of free cash flow in the quarter and $153 million of free cash flow in the first half of 2021;
- In June 2021 MEG along with four other oil sands operators who collectively represent 90% of Canada’s oil sands production formed the Oil Sands Pathway to Net Zero Alliance to work collectively with the federal and Alberta governments to achieve net zero GHG emissions from oil sands operations by 2050; and
- Subsequent to the quarter, MEG issued a notice to redeem US$100 million (approximately C$125 million) of MEG’s 6.50% senior secured second lien notes due January 2025.
Blend Sales Pricing
MEG realized an average AWB blend sales price of US$56.41 per barrel during the second quarter of 2021 compared to US$48.39 per barrel in the first quarter of 2021. The increase in average AWB blend sales price quarter over quarter was primarily a result of the average WTI price increasing by US$8.23 per barrel. MEG sold 45% of its sales volumes at the premium-priced U.S. Gulf Coast (“USGC”) in the second quarter of 2021 compared to 38% in the first quarter of 2021.
As sales volumes were consistent quarter over quarter, transportation and storage costs were also consistent averaging US$6.17 per barrel of AWB blend sales in the second quarter of 2021 compared to US$6.13 per barrel of AWB blend sales in the first quarter of 2021.
Bitumen production averaged 91,803 bbls/d in the second quarter of 2021, consistent with average bitumen production of 90,842 bbls/d in the first quarter of 2021.
Non–energy operating costs averaged $3.84 per barrel of bitumen sales in the second quarter of 2021 compared to $4.05 per barrel in the first quarter of 2021 primarily due to a 3% increase in bitumen sales volumes quarter over quarter. Energy operating costs, net of power revenue, averaged $1.70 per barrel in the second quarter of 2021 compared to $1.20 per barrel in the first quarter of 2021. MEG benefited from strong power prices on power sales from its cogeneration facilities whereby power revenue offset energy operating costs by 60% during the second quarter of 2021.
General & administrative expense (“G&A”) was $13 million, or $1.56 per barrel of production, in the second quarter of 2021 compared to $14 million, or $1.77 per barrel of production, in the first quarter of 2021. The difference in per barrel G&A expense was due to higher production in the second quarter of 2021 compared to the first quarter of 2021.
Adjusted Funds Flow and Net Earnings (Loss)
MEG’s bitumen realization averaged $60.09 per barrel in the second quarter of 2021 compared to $52.34 per barrel in the first quarter of 2021. The increase in average bitumen realization was due to the higher WTI price quarter over quarter. Partially offsetting the increase in bitumen realization during the second quarter of 2021, compared to the first quarter of 2021, was a realized commodity price risk management loss of $10.63 per barrel in the second quarter of 2021 compared to $8.80 per barrel in the first quarter of 2021. This reflects stronger WTI settlement prices compared to WTI fixed price contracts in place.
The Corporation’s cash operating netback averaged $31.30 per barrel in the second quarter of 2021 compared to $26.03 per barrel in the first quarter of 2021. The increased cash operating netback drove the increase in the Corporation’s adjusted funds flow from $127 million in the first quarter of 2021 to $166 million in the second quarter of 2021.
The Corporation recognized net earnings of $68 million in the second quarter of 2021 compared to a net loss of $17 million in the first quarter of 2021. This change was primarily the result of increased cash operating netback and a smaller unrealized loss on commodity price risk management.
MEG invested $70 million in the second quarter of 2021 compared to $70 million in the first quarter of 2021, which was primarily directed towards sustaining and maintenance activities during both periods.
COVID-19 Global Pandemic
MEG continues to proactively respond to the safety challenges associated with COVID-19 and remains committed to ensuring that the health and safety of all its personnel and business partners and the safe and reliable operation of the Christina Lake facility remain a top priority. MEG continues to apply screening procedures, including antigen screening and other protocols, ensuring the health and safety of its people.
Non-Core Asset Sale
During the quarter, MEG completed the sale of non-core industrial lands near Edmonton for cash proceeds of approximately $44 million, with proceeds received in July. The lands were purchased in 2013 at a cost of $39 million.
Optimization of Christina Lake Production Capacity
Inclusive of the non-core asset sale, MEG generated approximately $200 million of cash in excess of invested capital in the first half of 2021. Of this amount, the Corporation will direct $75 million to MEG’s 2021 capital investment program.
This $75 million of capital investment represents the majority of the estimated $125 million incremental well capital necessary to allow the Corporation to fully utilize the Christina Lake central plant facility’s oil processing capacity of approximately 100,000 bbls/d, prior to any impact from scheduled maintenance activity or outages.
The estimated $125 million total cost is less than MEG’s previous estimate of $150 million due to year-to-date field-wide production outperformance resulting from increased steam utilization, improved field reliability and completed and ongoing well optimization and recompletion work. This year-to-date outperformance provides the confidence for the Corporation to increase full year 2021 average production guidance from 88,000 – 90,000 bbls/d to 91,000 – 93,000 bbls/d.
MEG expects to invest the estimated $50 million of remaining incremental well capital required to return the Christina Lake facility to full utilization in the first half of 2022. Based on this level of incremental capital investment the Corporation expects to be able to fully utilize the oil processing capacity at its Christina Lake facility in the second half of 2022 post the planned turnaround at MEG’s Phase 2B facility in the second quarter of 2022. The turnaround, which is scheduled for the month of May 2022, is currently expected to impact full year 2022 production by approximately 5,000 bbls/d.
MEG announced today that the Corporation has issued a notice to redeem US$100 million (approximately C$125 million) of MEG’s 6.50% senior secured second lien notes due January 2025 at a redemption price of 103.25%, plus accrued and unpaid interest to, but not including, the redemption date. The redemption is expected to be completed on or about August 23, 2021.
Based on the current commodity price environment, MEG anticipates generating approximately $275 million of free cash flow in the second half of 2021, which will be directed to further debt repayment.
Based on better than expected production performance in the first half of 2021, MEG is revising its full year 2021 average production to 91,000 – 93,000 bpd.
G&A expense is now targeted to be in the range of $1.65 – $1.75 per barrel and non-energy operating costs are now expected to be in the range of $4.40 – $4.60 per barrel.
|Summary of 2021 Guidance||Revised Guidance
(July 22, 2021)
(May 3, 2021)
(December 7, 2020)
|Bitumen production – annual average||91,000 – 93,000 bbls/d||88,000 – 90,000 bbls/d||86,000 – 90,000 bbls/d|
|Non-energy operating costs||$4.40 – $4.60 per bbl||$4.60 – $5.00 per bbl||$4.60 – $5.00 per bbl|
|G&A expense||$1.65 – $1.75 per bbl||$1.70 – $1.80 per bbl||$1.70 – $1.80 per bbl|
|Capital expenditures||$335 million||$260 million||$260 million|
MEG is revising downward its expected sales into the USGC via Flanagan South and Seaway Pipeline systems (“FSP”) from 50% to approximately 40% of total AWB blend sales. This is lower than previous estimates due to continued higher than forecast apportionment on the Enbridge mainline system. As a result, MEG is revising downward its estimate of full year 2021 total transportation costs from a range of US$6.75 to US$7.25 per barrel of AWB blend sales to a range of US$6.00 to US$6.50 per barrel of AWB blend sales.
2021 Commodity Price Risk Management
In the second half of 2020, MEG entered into enhanced WTI fixed price hedges with sold put options for approximately 30% of forecast second half of 2021 bitumen production at an average price of US$46.18 per barrel. MEG has also hedged approximately 15% of its forecast Edmonton WTI:WCS differential exposure for the third quarter of 2021 at an average differential of US$11.05 per barrel. In addition, MEG has hedged approximately 35% of its expected condensate requirements at a landed-at-Edmonton price of 97% of WTI, approximately 30% of expected natural gas requirements at an average price of C$2.61 per GJ and fixed the sales price on approximately 30% of expected power available for sale at an average price of C$62.75 per MWh, each for the second half of 2021. The table below reflects MEG’s outstanding 2021 hedge positions.
|Q3 2021||Q4 2021|
|Enhanced WTI Fixed Price Hedges with Sold Put Options(1)|
|Weighted average fixed WTI price (US$/bbl) / Put option strike price (US$/bbl)||$ 46.18 /
|$ 46.18 /
|WTI:WCS Differential Hedges|
|Weighted average fixed WTI:WCS differential (US$/bbl)||$||(11.05)||$||—|
|Weighted average % of WTI landed in Edmonton (%)(3)||97||%||97||%|
|Natural Gas Hedges|
|Weighted average fixed AECO price (C$/GJ)||$||2.61||$||2.61|
|Weighted average fixed price (C$/MWh)||$||62.75||$||62.75|
|(1)||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$7.39 per barrel (the swap spread) on each barrel hedged in that month.|
|(2)||Includes approximately 3,000 bbls/d of physical forward condensate purchases for the second half of 2021 at a fixed discount to WTI.|
|(3)||The average % of WTI landed in Edmonton includes estimated net transportation costs to Edmonton.|
|(4)||Includes 5,000 GJ/d of physical forward natural gas purchases for the second half of 2021 at a fixed AECO price.|
|(5)||Represents physical forward power sales at a fixed power price.|
A conference call will be held to review MEG’s second quarter of 2021 operating and financial results at 6:30 a.m. Mountain Time (8:30 a.m. Eastern Time) on Friday, July 23rd, 2021. To participate, please dial the North American toll-free number 1-888-390-0546, or the international call number 1-416-764-8688.
A recording of the call will be available by 12 noon Mountain Time (2 p.m. Eastern Time) on the same day at www.megenergy.com/investors/presentations-and-events.
Operational and Financial Highlights
|Six months ended
|($millions, except as indicated)||2021||2020||Q2||Q1||Q4||Q3||Q2||Q1||Q4||Q3|
|Bitumen production – bbls/d||91,326||83,622||91,803||90,842||91,030||71,516||75,687||91,557||94,566||93,278|
|Bitumen sales – bbls/d||88,646||83,806||89,980||87,298||95,731||67,569||70,397||97,214||94,347||94,992|
|Bitumen realization – $/bbl||56.30||15.56||60.09||52.34||38.64||39.68||10.18||19.45||46.86||53.37|
|Net operating costs – $/bbl(1)||5.39||5.78||5.54||5.25||6.98||6.05||6.14||5.51||5.87||4.30|
|Non-energy operating costs – $/bbl||3.94||4.37||3.84||4.05||4.70||3.96||4.09||4.57||4.49||4.22|
|Cash operating netback – $/bbl(2)||28.73||20.62||31.30||26.03||18.66||16.58||25.84||16.83||28.33||32.44|
|General & administrative expense $/bbl(3)||1.66||1.66||1.56||1.77||1.65||1.50||1.29||1.96||2.25||1.66|
|Adjusted funds flow(4)||293||164||166||127||84||26||89||76||155||191|
|Per share, diluted||0.95||0.54||0.53||0.41||0.27||0.09||0.29||0.25||0.51||0.63|
|Net earnings (loss)||51||(364)||68||(17)||16||(9)||(80)||(284)||26||24|
|Per share, diluted||0.17||(1.21)||0.22||(0.06)||0.05||(0.03)||(0.26)||(0.95)||0.09||0.08|
|Cash and cash equivalents||159||120||159||54||114||49||120||62||206||154|
|Long-term debt – C$||2,820||3,096||2,820||2,852||2,912||3,030||3,096||3,212||3,123||3,257|
|Long-term debt – US$||2,273||2,274||2,273||2,268||2,283||2,274||2,274||2,275||2,409||2,459|
|(1)||Net operating costs include energy and non-energy operating costs, reduced by power revenue.|
|(2)||Cash operating netback is a non-GAAP measure and does not have a standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures used by other companies. Refer to the “NON-GAAP MEASURES” section of this Press Release.|
|(3)||General and administrative expense (“G&A”) per barrel is based on bitumen production volumes.|
|(4)||Refer to Note 19 of the June 30, 2021 interim consolidated financial statements for further details.|
Basis of Presentation
MEG prepares its financial statements in accordance with International Financial Reporting Standards (“IFRS”) and presents financial results in Canadian dollars ($ or C$), which is the Corporation’s functional currency.
Certain financial measures in this news release including free cash flow and cash operating netback are non-GAAP measures. These terms are not defined by IFRS and, therefore, may not be comparable to similar measures provided by other companies. These non-GAAP financial measures should not be considered in isolation or as an alternative for measures of performance prepared in accordance with IFRS.
Free Cash Flow
Free cash flow is presented to assist management and investors in analyzing performance by the Corporation as a measure of financial liquidity and the capacity of the business to repay debt. Free cash flow is calculated as adjusted funds flow less capital expenditures.
|Three months ended June 30||Six months ended June 30|
|Net cash provided by (used in) operating activities||$||180||$||117||$||192||$||216|
|Net change in non-cash operating working capital items||(20)||(48)||89||(78)|
|Funds flow from operations||160||69||281||138|
|Payments on onerous contracts||6||—||12||—|
|Adjusted funds flow||$||166||$||89||$||293||$||164|
|Free cash flow||$||96||$||69||$||153||$||90|
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 commitment to ensuring the health and safety of its personnel and safe and reliable operations of the Christina Lake facility; the Corporation’s intention to direct $75 million of cash in excess of invested capital in the first half of 2021 to the Corporation’s 2021 capital investment program; the Corporation’s estimate that $125 million incremental well capital will allow the Corporation to fully utilize the Christina Lake central plant facility’s oil processing capacity of approximately 100,000 bbs/d; the Corporation’s expectations regarding the remaining estimated $50 million incremental well capital required to return Christina Lake facility to full utilization; the Corporation’s expectations to be able to fully utilize the oil processing capacity at its Christina Lake facility in the second half of 2022; the Corporation’s expectations regarding the planned turnaround of its Phase 2B facility in the second quarter of 2022 and related impacts on production; the Corporation’s intention to redeem US$100 million of its 6.50% second lien notes due 2025; the Corporation’s expectations regarding free cash flow in the second half of 2021 and the application of free cash flow to further debt repayment; 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 sales into the USGC and full year 2021 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.
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SOURCE MEG Energy Corp.