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.
"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.
Operational Performance
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.
Capital Expenditures
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.
Debt Repayment
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.
Outlook
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)
|
Revised
Guidance
(May 3, 2021)
|
Original
Guidance
(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$62.75 per MWh,
each for the second half of 2021. The table below reflects MEG's
outstanding 2021 hedge positions.
|
|
|
|
Forecast
Period
|
|
|
Q3
2021
|
|
Q4
2021
|
|
WTI
Hedges
|
|
|
|
|
|
|
Enhanced WTI Fixed
Price Hedges with Sold Put Options(1)
|
|
|
|
|
|
|
Volume
(bbls/d)
|
|
29,000
|
|
|
29,000
|
|
Weighted average fixed
WTI price (US$/bbl) / Put option strike price (US$/bbl)
|
|
$ 46.18 /
$ 38.79
|
|
|
$ 46.18 /
$ 38.79
|
|
WTI:WCS
Differential Hedges
|
|
|
|
|
|
|
Volume
(bbls/d)
|
|
10,000
|
|
|
—
|
|
Weighted average fixed
WTI:WCS differential (US$/bbl)
|
$
|
(11.05)
|
|
$
|
—
|
|
Condensate
Hedges
|
|
|
|
|
|
|
Volume(2) (bbls/d)
|
|
14,028
|
|
|
14,028
|
|
Weighted average % of
WTI landed in Edmonton (%)(3)
|
|
97
|
%
|
|
97
|
%
|
Natural Gas
Hedges
|
|
|
|
|
|
|
Volume(4)
(GJ/d)
|
|
42,500
|
|
|
42,500
|
|
Weighted average fixed
AECO price (C$/GJ)
|
$
|
2.61
|
|
$
|
2.61
|
|
Power
Hedges
|
|
|
|
|
|
|
Quantity(5)
(MW)
|
|
35
|
|
|
35
|
|
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$7.39 per barrel (the swap spread) on each barrel
hedged in that month.
|
(2)
|
Includes
approximately 3,000 bbls/d of physical forward condensate purchases
for the second half of 2021 at a fixed discount to
WTI.
|
(3)
|
The average % of
WTI landed in Edmonton includes estimated net transportation costs
to Edmonton.
|
(4)
|
Includes 5,000
GJ/d of physical forward natural gas purchases for the second half
of 2021 at a fixed AECO price.
|
(5)
|
Represents
physical forward power sales at a fixed power price.
|
Conference Call
A conference call will be held to review MEG's second quarter of
2021 operating and financial results at 6:30
a.m. Mountain Time (8:30 a.m. Eastern
Time) on Friday, July 23rd,
2021. To participate, please dial the North American
toll-free number 1-888-390-0546, or the international call number
1-416-764-8688.
A recording of the call will be available by 12 noon Mountain Time (2 p.m.
Eastern Time) on the same day at
www.megenergy.com/investors/presentations-and-events.
Operational and Financial Highlights
|
|
|
|
|
|
Six months
ended
June 30
|
2021
|
2020
|
2019
|
($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
|
Steam-oil
ratio
|
2.38
|
2.31
|
2.39
|
2.37
|
2.31
|
2.36
|
2.32
|
2.31
|
2.27
|
2.26
|
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 $/bbl(3)
|
1.66
|
1.66
|
1.56
|
1.77
|
1.65
|
1.50
|
1.29
|
1.96
|
2.25
|
1.66
|
Adjusted funds
flow(4)
|
293
|
164
|
166
|
127
|
84
|
26
|
89
|
76
|
155
|
191
|
Per share,
diluted
|
0.95
|
0.54
|
0.53
|
0.41
|
0.27
|
0.09
|
0.29
|
0.25
|
0.51
|
0.63
|
Revenue
|
1,923
|
972
|
1,009
|
914
|
786
|
533
|
307
|
665
|
992
|
958
|
Net earnings
(loss)
|
51
|
(364)
|
68
|
(17)
|
16
|
(9)
|
(80)
|
(284)
|
26
|
24
|
Per share,
diluted
|
0.17
|
(1.21)
|
0.22
|
(0.06)
|
0.05
|
(0.03)
|
(0.26)
|
(0.95)
|
0.09
|
0.08
|
Capital
expenditures
|
140
|
74
|
70
|
70
|
40
|
36
|
20
|
54
|
72
|
40
|
Cash and cash
equivalents
|
159
|
120
|
159
|
54
|
114
|
49
|
120
|
62
|
206
|
154
|
Long-term debt -
C$
|
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.
|
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$), which is the
Corporation's functional currency.
Non-GAAP Measures
Certain financial measures in this news release including free
cash flow and cash operating netback are non-GAAP measures. These
terms are not defined by IFRS and, therefore, may not be comparable
to similar measures provided by other companies. These non-GAAP
financial measures should not be considered in isolation or as an
alternative for measures of performance prepared in accordance with
IFRS.
Free Cash Flow
Free cash flow is presented to assist management and investors
in analyzing performance by the Corporation as a measure of
financial liquidity and the capacity of the business to repay debt.
Free cash flow is calculated as adjusted funds flow less capital
expenditures.
|
|
|
|
|
Three months ended
June 30
|
|
Six months ended
June 30
|
($millions)
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
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
|
Adjustments:
|
|
|
|
|
|
|
|
|
Payments on onerous
contracts
|
|
6
|
|
—
|
|
12
|
|
—
|
Contract
cancellation
|
|
—
|
|
20
|
|
—
|
|
26
|
Adjusted funds
flow
|
$
|
166
|
$
|
89
|
$
|
293
|
$
|
164
|
Capital
expenditures
|
|
(70)
|
|
(20)
|
|
(140)
|
|
(74)
|
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.
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 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.
About MEG
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
For further information, please contact:
Investor Relations
T 587.293.6045
E invest@megenergy.com
Media Relations
T 403.775.1131
E media@megenergy.com
SOURCE MEG Energy Corp.