MEG Energy announces third quarter results including successful completion of major plant turnaround, increased production guidance and further cost reductions
All financial figures are in Canadian dollars ($ or C$) and all references to barrels are per barrel of bitumen sales unless otherwise noted
CALGARY, AB, Oct. 26, 2020 /CNW/ - MEG Energy Corp. (TSX: MEG) ("MEG" or the "Corporation") reported its third quarter of 2020 operational and financial results.
MEG continues to proactively respond to the safety and financial 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.
"Our 75-day major scheduled plant turnaround was successfully completed in August with production coming back stronger than previously expected" said Derek Evans, President and Chief Executive Officer. "As we head into year end, we are increasing annual production guidance, decreasing annual G&A and non-energy operating cost guidance and expect to build free cash flow through the balance of the year with 80% of our WTI exposure on our fourth quarter sales hedged at approximately US$46 per barrel."
MEG remains well positioned from a financial liquidity perspective, benefiting not only from its significant 2020 hedge book and the term and structure of its outstanding indebtedness and credit facility, but also from the low decline and low cost structure of its high-quality Christina Lake asset.
Third quarter financial and operating highlights include:
- Adjusted funds flow of $27 million ($0.09 per share), impacted by lower sales volumes due to major planned turnaround activities;
- Quarterly production volumes of 71,516 barrels per day (bbls/d) at a steam-oil ratio (SOR) of 2.36, while completing major planned turnaround activities. Due to better than expected production levels during and post-turnaround, annual average production guidance has been revised higher to 81,000 - 82,000 bbls/d;
- Net operating costs of $6.05 per barrel, including record low non-energy operating costs of $3.96 per barrel and power sales which had the impact of offsetting 34% of per barrel energy operating costs, resulting in a net energy operating cost of $2.09 per barrel;
- Total capital investment of $36 million in the quarter was directed to sustaining capital and planned turnaround activities. Approximately 75% of MEG's $150 million 2020 capital budget has been invested to the end of the third quarter; and
- $49 million of cash-on-hand at September 30, 2020 with approximately 80% of WTI exposure on fourth quarter forecast sales hedged at average WTI price of US$45.76. MEG's $800 million modified covenant-lite revolver remains undrawn.
Blend Sales Pricing and North American Market Access
MEG realized an average AWB blend sales price of US$34.13 per barrel during the third quarter of 2020 compared to US$15.12 per barrel in the second 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$13.08 per barrel in addition to the average WTI:AWB differential at Edmonton narrowing by US$2.96 per barrel. MEG sold 62% of its sales volumes to the U.S. Gulf Coast ("USGC") in the third quarter of 2020 compared to 35% in the second quarter of 2020. The increase in sales to the USGC in the third quarter of 2020 is primarily a result of the Corporation's increased contracted 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$10.07 per barrel of AWB blend sales in the third quarter of 2020 compared to US$5.92 per barrel of AWB blend sales in the second quarter of 2020. The increase in transportation and storage costs is primarily due to the fixed costs associated with increased FSP contracted capacity and lower apportionment on the Enbridge mainline. Also, the increased costs were allocated to 7% lower AWB blend sales volumes quarter over quarter. The additional transportation capacity afforded by higher FSP contracted capacity and lower apportionment was underutilized by MEG during the third quarter of 2020 due to the planned turnaround. Subject to the level of actual apportionment on the Enbridge mainline system, transportation costs are expected to average between US$7.50 and US$8.50 per barrel of AWB blend sales through the remainder of 2020 and 2021.
MEG's AWB blend sales by rail was 13,189 bbls/d (all FOB Edmonton) in the third quarter of 2020, representing 14% of total blend sales, compared to 4,391 bbls/d (all FOB Edmonton) in the second quarter of 2020. The increase in barrels sold via rail quarter over quarter was a result of a balanced approach to rail cost mitigation efforts undertaken by the Corporation in the third quarter of 2020 given the relative economics of sales by contracted rail transportation compared to pipeline transportation costs.
Operational Performance
Bitumen production averaged 71,516 bbls/d in the third quarter of 2020, compared to 75,687 bbls/d in the second quarter of 2020. Bitumen production in the third quarter of 2020 was impacted by major planned turnaround activities at the Phase 1 and 2 facilities, which began in early June 2020 and were completed mid-August 2020. The 2020 turnaround was extended in duration to 75 days and expanded in scope, relative to base budget, in order to minimize staff levels at site during COVID-19 and maximize utilization of MEG'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.
Non-energy operating costs averaged $3.96 per barrel of bitumen sales in the third quarter of 2020 compared to $4.09 per barrel in the second quarter of 2020. Net energy operating costs averaged $2.09 per barrel in the third quarter of 2020 compared to $2.05 in the second quarter of 2020. During the nine months ended September 30, 2020, the Corporation was able to benefit from non-recurring cost reductions of approximately $13 million including the Canadian Emergency Wage Subsidy ("CEWS") program.
General & administrative expense ("G&A") was $10 million, or $1.50 per barrel of production, in the third quarter of 2020 compared to $9 million, or $1.29 per barrel of production, in the second quarter of 2020. Total aggregate G&A has remained relatively consistent quarter over quarter and included the impact of MEG's continuing efforts to drive efficiency into its cost structure through salary rollbacks, reductions in staffing levels and vendor concessions, as well as various government led initiatives, including CEWS. During the nine months ended September 30, 2020, the Corporation was able to benefit from non-recurring cost reductions of approximately $5 million including the CEWS program.
Adjusted Funds Flow and Net Loss
MEG's bitumen realization averaged $39.68 per barrel in the third quarter of 2020 compared to $10.18 per barrel in the second quarter of 2020. The increase in average bitumen realization quarter over quarter was driven by the higher WTI price and lower diluent cost. Also, a higher portion of sales volumes reached the USGC market, increasing the realized price earned.
Offsetting the increase in bitumen realization during the third quarter of 2020, compared to the second quarter of 2020, was a decrease in the realized commodity risk management gain of $31.91 per barrel, quarter over quarter, and an increase in transportation and storage costs of $6.78 per barrel, quarter over quarter. The decrease in the realized commodity risk management gain was driven by an increase in the WTI price compared to the WTI fixed price contracts in place. The increase in transportation and storage costs was due to the increased fixed costs associated with the increased transportation capacity on FSP. These changes contributed to the decrease in the Corporation's cash operating netback to $16.58 per barrel in the third quarter of 2020 compared to $25.84 per barrel in the second quarter of 2020. The decreased cash operating netback drove the decrease in the Corporation's adjusted funds flow from $89 million in the second quarter of 2020 to $27 million in the third quarter of 2020.
The Corporation recognized a net loss of $9 million in the third quarter of 2020 compared to a net loss of $80 million in the second quarter of 2020. The decrease in the net loss in the third quarter of 2020, compared to the second quarter of 2020, was primarily the result of a decreased unrealized loss on commodity risk management contracts partially offset by decreased cash operating netback and a decreased unrealized gain on foreign exchange.
Capital Expenditures
MEG invested $36 million in the third quarter of 2020 compared to $20 million in the second quarter of 2020. Of the $36 million, $21 million was directed towards sustaining and maintenance activities with the remaining $15 million related to the 75-day planned turnaround at the Christina Lake Phase 1 and 2 facilities which was completed mid-August.
COVID-19 Global Pandemic
The Corporation continues to proactively respond to the safety and financial 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 currently remain in place to ensure continued safe and reliable operations. During the third quarter of 2020, the Corporation focused on a transition to resuming normal operations which included the majority of office staff returning to the Calgary office and site personnel resuming normal operating schedules at the Christina Lake site. Management will continue to monitor this 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.
Outlook
Based on better than expected production performance during and post-turnaround, MEG is revising upward its full year 2020 average production from 78,000 – 80,000 bbls/d to 81,000 – 82,000 bbls/d. Compared to the original guidance of 94,000 – 97,000 bbls/d announced November 21, 2019, approximately half of the difference is due to the impact of the scheduled 75-day major turnaround at the Christina Lake Phase 1 and 2 facilities completed mid-August. The remainder of the difference results from a combination of previously disclosed weather-related production impacts in the first quarter of 2020, voluntary price-related production curtailments in the second quarter of 2020 and the impact of reduced well capital throughout 2020, which made up approximately 80% of the combined $100 million reduction in capital spending announced on March 10 and May 4 of 2020.
G&A expense is now targeted to be in the range of $45 – $47.5 million, or approximately $17.5 million lower than original guidance. Non-energy operating costs are now expected to be in the range of $130 - $135 million, or approximately $32.5 million lower than original guidance. Of the $50 million aggregate reduction in expected costs, approximately $22 million are a result of temporary cost reductions while the remaining $28 million in cost reductions are a result of a continued optimization of operations, reduction in staffing levels and rationalization of ongoing administrative costs.
MEG expects to release its 2021 capital budget in December. While the development of the 2021 capital budget remains in progress, it will be designed to be fully funded with internally generated funds. This is consistent with MEG's financial discipline in 2020, where the current year's capital program remains on track to be fully funded with internally generated funds.
Guidance Update
Summary of 2020 |
Revised Guidance |
Previously Revised |
Previously Revised |
Previously Revised |
Original Guidance |
Production (1H20) |
N/A |
N/A |
76,000 bbls/d |
N/A |
N/A |
Production |
81,000 - 82,000 |
78,000-80,000 |
N/A |
93,000-95,000 |
94,000-97,000 |
Non-energy |
$130-$135 million(1) |
$140-$150 million |
$140-$150 million |
$155-$165 million |
$160-$170 million |
G&A expense |
$45-$47.5 million(1) |
$52.5-$55 million |
$52.5-$55 million |
$60-$62.5 million |
$62.5-$65 million |
Capital expenditures |
$150 million |
$150 million |
$150 million |
$200 million |
$250 million |
(1) |
Revised non-energy operating costs and G&A expense guidance ranges include approximately $15 million and $7 million, respectively, of temporary cost reductions including CEWS. |
Financial Liquidity
Notwithstanding multi-decade low crude oil prices, MEG generated $85 million of free cash flow in the nine months ended September 30, 2020, and exited the third quarter of 2020 with its credit facility undrawn and $49 million of cash on hand. MEG expects to build free cash flow through the fourth quarter of 2020 with 80% of our WTI exposure hedged at US$45.76 per barrel.
The Corporation's earliest long-term debt maturity is in 2024, represented by US$600 million of senior unsecured notes due March 2024. None of the Corporation's outstanding long-term debt contain financial maintenance covenants. Additionally, MEG's modified covenant-lite $800 million revolving credit facility has no financial maintenance covenant unless drawn in excess of $400 million. If drawn in excess of $400 million, MEG is required to maintain a quarterly first lien net leverage ratio (first lien net debt to last twelve-month EBITDA) of 3.5 or less. Under MEG's credit facility, first lien net debt is calculated as debt under the credit facility plus other debt that is secured on a pari passu basis with the credit facility, less cash on hand.
Q4 2020 and Full Year 2021 Commodity Hedges
For the fourth quarter of 2020, MEG has entered into benchmark WTI fixed price hedges for approximately 80% of forecast bitumen production at an average price of US$45.76 per barrel.
For full year 2021, to date MEG has entered into enhanced WTI fixed price hedges with sold put options for approximately 25% of forecast bitumen production at an average price of US$46.25 per barrel. If in 2021 WTI averages US$38.71 per barrel (the sold put option) or better, MEG will receive US$46.25 per barrel (the fixed price swap) on each barrel hedged. If in 2021 WTI averages less than US$38.71 per barrel, MEG will receive the average 2021 WTI price plus US$7.54 per barrel (the swap spread) on each barrel hedged.
The table below reflects MEG's current Q4 2020 and full year 2021 financial and physical hedge positions.
Forecast Period |
||||
Q4 2020 |
Full Year 2021 |
|||
WTI Hedges |
||||
WTI Fixed Price Hedges |
||||
Volume (bbls/d) |
69,665 |
— |
||
Weighted average fixed WTI price (US$/bbl) |
$ |
45.76 |
$ |
— |
Enhanced WTI Fixed Price Hedges with Sold Put Options(1) |
||||
Volume (bbls/d) |
24,500 |
21,000 |
||
Weighted average fixed WTI price (US$/bbl) / |
||||
Put option strike price (US$/bbl) |
$ |
59.11 / $ 52.00 |
$ |
46.25 / $ 38.71 |
WTI:WCS Differential Hedges |
||||
Volume(2) (bbls/d) |
38,896 |
— |
||
Weighted average fixed WTI:WCS differential (US$/bbl) |
$ |
(20.12) |
$ |
— |
Condensate Hedges |
||||
Volume(3) (bbls/d) |
23,208 |
10,950 |
||
Weighted average % of WTI landed in Edmonton (%)(4) |
101 % |
93 % |
||
Natural Gas Hedges |
||||
Volume(5) (GJ/d) |
— |
30,000 |
||
Weighted average fixed AECO price (C$/GJ) |
— |
$ |
2.68 |
|
(1) |
Includes WTI fixed price swaps and WTI sold put options entered into for both Q4 2020 and the full year 2021. For Q4 2020, MEG's average realized WTI price on these hedges is US$7.11 per barrel above actual while WTI prices remain below US$52.00 per barrel. For the full year 2021, MEG's average realized WTI price on these hedges is US$46.25 per barrel, when WTI prices are above US$38.71 per barrel, or US$7.54 per barrel above actual when WTI prices are below US$38.71 per barrel. |
(2) |
Includes approximately 10,900 bbls/d of physical forward blend sales for Q4 2020 at a fixed WTI:AWB differential. |
(3) |
Includes approximately 8,200 bbls/d of physical forward condensate purchases for Q4 2020. |
(4) |
Where applicable, the average % of WTI landed in Edmonton includes estimated net transportation costs to Edmonton. |
(5) |
Includes 5,000 GJ/d of physical forward purchases for 2021 at a fixed AECO price. |
Conference Call
A conference call will be held to review MEG's third quarter 2020 operating and financial results at 6:30 a.m. Mountain Time (8:30 a.m. Eastern Time) on Tuesday, October 27th, 2020. To participate, please dial the North American toll-free number 1-888-390-0546, or the international call number 1-416-764-8688.
A recording of the call will be available by 12 noon Mountain Time (2 p.m. Eastern Time) on the same day at www.megenergy.com/investors/presentations-and-events.
Operational and Financial Highlights
Nine months ended |
2020 |
2019 |
2018 |
|||||||
($millions, except as indicated) |
2020 |
2019 |
Q3 |
Q2 |
Q1 |
Q4 |
Q3 |
Q2 |
Q1 |
Q4 |
Bitumen production - bbls/d |
79,557 |
92,582 |
71,516 |
75,687 |
91,557 |
94,566 |
93,278 |
97,288 |
87,113 |
87,582 |
Steam-oil ratio |
2.33 |
2.21 |
2.36 |
2.32 |
2.31 |
2.27 |
2.26 |
2.16 |
2.20 |
2.22 |
Bitumen sales - bbls/d |
78,354 |
93,330 |
67,569 |
70,397 |
97,214 |
94,347 |
94,992 |
95,120 |
89,822 |
88,283 |
Bitumen realization - $/bbl |
22.54 |
55.38 |
39.68 |
10.18 |
19.45 |
46.86 |
53.37 |
62.23 |
50.21 |
15.31 |
Net operating costs - $/bbl(1) |
5.85 |
5.01 |
6.05 |
6.14 |
5.51 |
5.87 |
4.30 |
4.66 |
6.17 |
4.55 |
Non-energy operating costs - $/bbl |
4.25 |
4.64 |
3.96 |
4.09 |
4.57 |
4.49 |
4.22 |
4.53 |
5.22 |
4.25 |
Cash operating netback - $/bbl(2) |
19.45 |
33.47 |
16.58 |
25.84 |
16.83 |
28.33 |
32.44 |
37.88 |
29.80 |
7.14 |
Adjusted funds flow(3) |
194 |
569 |
27 |
89 |
78 |
157 |
192 |
227 |
151 |
(37) |
Per share, diluted |
0.63 |
1.90 |
0.09 |
0.29 |
0.26 |
0.51 |
0.63 |
0.76 |
0.50 |
(0.13) |
Revenue |
1,505 |
2,938 |
533 |
307 |
665 |
992 |
958 |
1,062 |
919 |
520 |
Net earnings (loss) |
(373) |
(87) |
(9) |
(80) |
(284) |
26 |
24 |
(64) |
(48) |
(199) |
Per share, diluted |
(1.24) |
(0.29) |
(0.03) |
(0.26) |
(0.95) |
0.09 |
0.08 |
(0.21) |
(0.16) |
(0.67) |
Capital expenditures |
109 |
126 |
36 |
20 |
54 |
72 |
40 |
32 |
53 |
144 |
Cash and cash equivalents |
49 |
154 |
49 |
120 |
62 |
206 |
154 |
399 |
154 |
318 |
Long-term debt - C$ |
3,030 |
3,257 |
3,030 |
3,096 |
3,212 |
3,123 |
3,257 |
3,582 |
3,660 |
3,740 |
Long-term debt - US$ |
2,274 |
2,459 |
2,274 |
2,274 |
2,275 |
2,409 |
2,459 |
2,737 |
2,740 |
2,741 |
(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 20 of the September 30, 2020 interim consolidated financial statements for further details. |
ADVISORY
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$), which is the Corporation's functional currency.
Non-GAAP Measures
Certain financial measures in this news release including free cash flow and cash operating netback are non-GAAP measures. These terms are not defined by IFRS and, therefore, may not be comparable to similar measures provided by other companies. These non-GAAP financial measures should not be considered in isolation or as an alternative for measures of performance prepared in accordance with IFRS.
Free Cash Flow
Free cash flow is presented to assist management and investors in analyzing performance by the Corporation as a measure of financial liquidity and the capacity of the business to repay debt. Free cash flow is calculated as adjusted funds flow less capital expenditures.
Three months ended |
Nine months ended |
|||||||
($millions) |
2020 |
2019 |
2020 |
2019 |
||||
Net cash provided by (used in) operating activities |
$ |
(31) |
$ |
174 |
$ |
186 |
$ |
406 |
Net change in non-cash operating working capital items |
50 |
17 |
(28) |
162 |
||||
Funds flow from operations |
19 |
191 |
158 |
568 |
||||
Adjustments: |
||||||||
Contract cancellation(1) |
7 |
— |
33 |
— |
||||
Decommissioning expenditures |
1 |
1 |
3 |
1 |
||||
Adjusted funds flow |
$ |
27 |
$ |
192 |
$ |
194 |
$ |
569 |
Capital expenditures |
(36) |
(40) |
(109) |
(126) |
||||
Free cash flow |
$ |
(9) |
$ |
152 |
$ |
85 |
$ |
443 |
(1) |
Costs 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. Contract cancellation costs or recoveries are excluded from adjusted funds flow as they are not considered part of ordinary continuing operating results. |
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.
Forward-Looking Information
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 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; the Corporation's expectation of production coming back stronger than anticipated post-turnaround; the Corporation's ability to build free cash flow through the balance of the year; the Corporation's actions taken to protect its financial liquidity, including the Corporation's hedge book, the term and structure of its outstanding indebtedness and credit facility, and the low decline, low cost structure and high quality Christina Lake asset; the Corporation's ongoing financial liquidity; the Corporation's expectations regarding transportation costs for the remainder of 2020 and for 2021; the impact of the major turnaround at the Christina Lake facility, including the impact on 2021 turnaround requirements; all statements relating to the Corporation's revised guidance, including full year 2020 production, non-energy operating costs, general and administrative expenses and capital expenditures; the Corporation's expectations regarding its 2021 capital budget and its ability to fund the remainder of its 2020 capital budget and its 2021 capital budget from internally generated funds; and all statements relating to the Corporation's 2020 and 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, level of apportionment on the Enbridge mainline, the level of contango in benchmark crude oil prices, 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; extent and timelines of the Alberta Government's mandatory production curtailment program, 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; ability to reduce oil sands production, including without negative impacts to its assets; forecast production volumes are subject to potential further ramp down of production based on business and market conditions; 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; 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; legislative and regulatory changes to, amongst other things, tax, land use, royalty and environmental laws and production curtailment; 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; securing and maintaining the necessary regulatory approvals and financing to proceed with MEG's future phases and the expansion and/or operation of MEG's projects; access to pipeline and rail transportation; timing of completion, commissioning, and start-up, of MEG's turnarounds, and of future phases, expansions and projects; 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 production to desired levels; 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; continued weakness and volatility of crude oil and other petroleum products due to decreased global demand due to the COVID-19 pandemic; 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 2019 Annual Management's Discussion and Analysis ("MD&A") and 2019 Annual Consolidated Financial Statements are available at www.megenergy.com/investors and at www.sedar.com.
About MEG
MEG is an energy company focused on sustainable in situ thermal oil production in the southern Athabasca 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 production to refiners throughout North America and internationally.
Learn more at: www.megenergy.com
For further information, please contact:
Investor Relations
T 587.293.6045
E [email protected]
Media Relations
T 587.233.8396
E [email protected]
SOURCE MEG Energy Corp.
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