All financial figures are in Canadian dollars ($ or C$) and all
references to barrels are per barrel of bitumen unless otherwise
noted
CALGARY, AB, Nov. 8, 2021 /CNW/ - MEG Energy Corp. (TSX:
MEG) "MEG" or the "Corporation") reported its third 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 third quarter was another strong operational quarter for
MEG as production levels benefited from our team's continued focus
on plant reliability, steam utilization and ongoing well
optimization." said Derek Evans,
President and Chief Executive Officer. "Given what we are
seeing operationally we have upwardly revised our annual production
guidance and look forward to a strong finish to 2021."
Third quarter financial and operating highlights include:
- Adjusted funds flow of $239
million ($0.77 per share),
impacted by a realized commodity price risk management loss in the
quarter of $66 million ($0.21 per share);
- Quarterly production volumes of 91,506 barrels per day (bbls/d)
at a steam–oil ratio (SOR) of 2.56. Based on strong
operational performance, annual average production guidance has
been upwardly revised from 91,000 – 93,000 bbls/d to 92,500 –
93,500 bbls/d;
- Net operating costs of $7.17 per
barrel, including non–energy operating costs of $4.46 per barrel. Power revenue offset energy
operating costs by 43%, resulting in a net impact of $2.71 per barrel. Year to date, power revenue has
offset approximately 60% of MEG's energy operating costs;
- Total capital investment of $84
million in the quarter with the majority directed towards
sustaining and maintenance activities, resulting in $155 million of free cash flow in the quarter;
and
- During the quarter MEG redeemed US$100
million (approximately $125
million) of MEG's 6.5% senior secured second lien notes due
January 2025.
Blend Sales Pricing
MEG realized an average AWB blend sales price of US$59.15 per barrel during the third quarter of
2021 compared to US$56.41 per barrel
in the second 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$4.49 per barrel. MEG sold 38% of its sales
volumes at the premium-priced U.S. Gulf Coast ("USGC") in the third
quarter of 2021 compared to 45% in the second quarter of 2021 due
to higher apportionment levels on the Enbridge mainline system
during the third quarter of 2021.
The reduction in sales volumes sold at the USGC quarter over
quarter was consistent with the reduction in transportation and
storage costs which averaged US$5.75
per barrel of AWB blend sales in the third quarter of 2021 compared
to US$6.17 per barrel of AWB blend
sales in the second quarter of 2021.
Operational Performance
Bitumen production averaged 91,506 bbls/d in the third quarter
of 2021, consistent with average bitumen production of 91,803
bbls/d in the second quarter of 2021.
Non–energy operating costs averaged $4.46 per barrel of bitumen sales in the third
quarter of 2021 compared to $3.84 per
barrel in the second quarter of 2021 primarily due to planned
maintenance activities. Energy operating costs, net of power
revenue, averaged $2.71 per barrel in
the third quarter of 2021 compared to $1.70 per barrel in the second quarter of 2021.
This increase quarter over quarter resulted from stronger natural
gas prices and lower power sales from its cogeneration facilities.
Power revenue offset energy operating costs by 43% during the third
quarter of 2021 compared to 60% during the second quarter of 2021.
Year to date, power revenue has offset approximately 60% of MEG's
energy operating costs.
General & administrative expense ("G&A") was relatively
consistent quarter over quarter with $14
million, or $1.72 per barrel
of production, in the third quarter of 2021 compared to
$13 million, or $1.56 per barrel of production, in the second
quarter of 2021.
Adjusted Funds Flow and Net Earnings (Loss)
The Corporation's cash operating netback averaged $37.31 per barrel in the third quarter of 2021
compared to $31.30 per barrel in the
second quarter of 2021. This increase in cash operating netback was
primarily driven by the increase in average bitumen realization due
to the higher WTI price, as well as a lower realized commodity
price risk management loss quarter over quarter. The increased cash
operating netback was the main driver for the increase in the
Corporation's adjusted funds flow from $166
million in the second quarter of 2021 to $239 million in the third quarter of 2021.
The Corporation recognized net earnings of $54 million in the third quarter of 2021 compared
to net earnings of $68 million in the
second quarter of 2021. This decrease in net earnings was primarily
the result of an unrealized foreign exchange loss in the third
quarter of 2021 compared to an unrealized foreign exchange gain in
the second quarter of 2021. This decrease was partially offset by
increased cash operating netback quarter over quarter and by an
unrealized gain on risk management in the third quarter of 2021
compared to an unrealized loss on risk management in the second
quarter of 2021.
Capital Expenditures
MEG invested $84 million in the
third quarter of 2021 compared to $70
million in the second quarter of 2021. Capital invested in
the quarter was directed towards sustaining and maintenance
activities as well as 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. As
previously disclosed in the Corporation's second quarter 2021
release, the total investment for this optimization initiative is
approximately $125 million with
$75 million included in the 2021
capital investment budget and the remainder expected to be invested
in the first half of 2022.
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.
Debt Repayment
As previously announced, during the third quarter of 2021 the
Corporation continued to prioritize debt repayment with the
redemption of US$100 million of the
Corporation'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 of August 23,
2021.
Since the beginning of 2018 the Corporation has repaid
US$1.6 billion of outstanding
indebtedness and remains committed to continued debt reduction as a
key component of its capital allocation strategy. All available
free cash flow generated in the second half of 2021 will be
directed to further debt repayment.
Outlook
Based on better than expected production performance MEG is
revising its full year 2021 average production to 92,500 – 93,500
bbls/d.
|
|
|
|
|
Summary of 2021
Guidance
|
Revised
Guidance
|
Revised
Guidance
|
Revised
Guidance
|
Original
Guidance
|
(November 8,
2021)
|
(July 22,
2021)
|
(May 3,
2021)
|
(December 7,
2020)
|
Bitumen production -
annual average
|
92,500 - 93,500
bbls/d
|
91,000 - 93,000
bbls/d
|
88,000 - 90,000
bbls/d
|
86,000 - 90,000
bbls/d
|
Non-energy operating
costs
|
$4.40 - $4.50 per
bbl
|
$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
|
$1.65 - $1.75 per
bbl
|
$1.70 - $1.80 per
bbl
|
$1.70 - $1.80 per
bbl
|
Capital
expenditures
|
$335 million
|
$335 million
|
$260 million
|
$260 million
|
MEG's estimate of full year 2021 total transportation costs
range from US$6.00 to US$6.50 per barrel of AWB blend sales.
MEG plans to release its 2022 capital and operating budget on or
about November 29, 2021.
2021 Commodity Price Risk Management
During the second half of 2020, MEG entered into enhanced WTI
fixed price hedges with sold put options for approximately 30% of
forecast bitumen production for the fourth quarter of 2021 at an
average price of US$46.18 per barrel.
Additionally, MEG has hedged approximately 30% of its expected
condensate requirements at a landed-at-Edmonton price equivalent to 98% of WTI,
approximately 30% of expected natural gas requirements at an
average AECO 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$62.75 per MWh, each for the fourth quarter of
2021. The table below reflects MEG's outstanding fourth
quarter of 2021 hedge positions.
MEG has not entered into any WTI or WTI:WCS differential hedges
for 2022.
|
|
|
Forecast
Period
|
|
Q4
2021
|
WTI
Hedges
|
|
Enhanced WTI Fixed
Price Hedges with Sold Put Options(1)
|
|
Volume
(bbls/d)
|
29,000
|
|
Weighted average fixed
WTI price (US$/bbl) / Put option strike price (US$/bbl)
|
$ 46.18 / $
38.79
|
|
|
Condensate
Hedges
|
|
Volume(2)
(bbls/d)
|
14,028
|
|
Weighted average % of
WTI price landed in Edmonton (%)(3)
|
98
|
%
|
|
|
Natural Gas
Hedges
|
|
Volume(4)
(GJ/d)
|
42,500
|
|
Weighted average fixed
AECO price (C$/GJ)
|
$
|
2.61
|
|
|
|
Power
Hedges
|
|
Quantity(5)(MW)
|
35
|
|
Weighted average fixed
price (C$/MWh)
|
$
|
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$7.39 per barrel (the swap spread) on each barrel
hedged in that month.
|
(2)
|
Includes
approximately 3,000 bbls/d of physical forward condensate purchases
for the fourth quarter of 2021 at a fixed discount to
WTI.
|
(3)
|
The average % of WTI
landed in Edmonton includes estimated net transportation costs to
Edmonton.
|
(4)
|
Includes 5,000 GJ/d
of physical forward natural gas purchases for the fourth quarter of
2021 at a fixed AECO price.
|
(5)
|
Represents physical
forward power sales at a fixed power price.
|
Conference Call
A conference call will be held to review MEG's third quarter of
2021 operating and financial results at 6:30
a.m. Mountain Time (8:30 a.m. Eastern
Time) on Tuesday, November 9th,
2021. To participate, please dial the North American
toll-free number 1-888-390-0546, or the international call number
1-416-764-8688.
A recording of the call will be available by 12 noon Mountain Time (2 p.m.
Eastern Time) on the same day at
www.megenergy.com/investors/presentations-and-events.
Operational and Financial Highlights
|
|
|
|
|
|
Nine months
ended
|
|
|
|
September
30
|
2021
|
2020
|
2019
|
($millions, except
as indicated)
|
2021
|
2020
|
Q3
|
Q2
|
Q1
|
Q4
|
Q3
|
Q2
|
Q1
|
Q4
|
Bitumen production -
bbls/d
|
91,386
|
79,557
|
91,506
|
91,803
|
90,842
|
91,030
|
71,516
|
75,687
|
91,557
|
94,566
|
|
|
|
|
|
|
|
|
|
|
|
Steam-oil
ratio
|
2.44
|
2.33
|
2.56
|
2.39
|
2.37
|
2.31
|
2.36
|
2.32
|
2.31
|
2.27
|
|
|
|
|
|
|
|
|
|
|
|
Bitumen sales -
bbls/d
|
89,861
|
78,354
|
92,251
|
89,980
|
87,298
|
95,731
|
67,569
|
70,397
|
97,214
|
94,347
|
|
|
|
|
|
|
|
|
|
|
|
Bitumen realization -
$/bbl
|
59.28
|
22.54
|
64.91
|
60.09
|
52.34
|
38.64
|
39.68
|
10.18
|
19.45
|
46.86
|
|
|
|
|
|
|
|
|
|
|
|
Net operating costs -
$/bbl(1)
|
6.00
|
5.85
|
7.17
|
5.54
|
5.25
|
6.98
|
6.05
|
6.14
|
5.51
|
5.87
|
|
|
|
|
|
|
|
|
|
|
|
Non-energy operating
costs - $/bbl
|
4.12
|
4.25
|
4.46
|
3.84
|
4.05
|
4.70
|
3.96
|
4.09
|
4.57
|
4.49
|
|
|
|
|
|
|
|
|
|
|
|
Cash operating netback
- $/bbl(2)
|
31.71
|
19.45
|
37.31
|
31.30
|
26.03
|
18.66
|
16.58
|
25.84
|
16.83
|
28.33
|
|
|
|
|
|
|
|
|
|
|
|
General &
administrative expense $/bbl(3)
|
1.68
|
1.61
|
1.72
|
1.56
|
1.77
|
1.65
|
1.50
|
1.29
|
1.96
|
2.25
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted funds
flow(4)
|
532
|
191
|
239
|
166
|
127
|
84
|
26
|
89
|
76
|
155
|
Per share,
diluted
|
1.71
|
0.62
|
0.77
|
0.53
|
0.41
|
0.27
|
0.09
|
0.29
|
0.25
|
0.51
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
3,014
|
1,505
|
1,091
|
1,009
|
914
|
786
|
533
|
307
|
665
|
992
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings
(loss)
|
105
|
(373)
|
54
|
68
|
(17)
|
16
|
(9)
|
(80)
|
(284)
|
26
|
Per share,
diluted
|
0.34
|
(1.24)
|
0.17
|
0.22
|
(0.06)
|
0.05
|
(0.03)
|
(0.26)
|
(0.95)
|
0.09
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
224
|
109
|
84
|
70
|
70
|
40
|
36
|
20
|
54
|
72
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash
equivalents
|
210
|
49
|
210
|
159
|
54
|
114
|
49
|
120
|
62
|
206
|
Long-term debt -
C$
|
2,769
|
3,030
|
2,769
|
2,820
|
2,852
|
2,912
|
3,030
|
3,096
|
3,212
|
3,123
|
Long-term debt -
US$
|
2,172
|
2,274
|
2,172
|
2,273
|
2,268
|
2,283
|
2,274
|
2,274
|
2,275
|
2,409
|
(1)
|
Net operating costs
include energy and non-energy operating costs, reduced by power
revenue.
|
(2)
|
Cash operating
netback is a non-GAAP measure and does not have a standardized
meaning prescribed by IFRS and therefore may not be
comparable to similar measures used by other companies. 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 September 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$), which is the
Corporation's functional currency.
Non-GAAP Measures
Certain financial measures in this news release including free
cash flow and cash operating netback are non-GAAP measures. These
terms are not defined by IFRS and, therefore, may not be comparable
to similar measures provided by other companies. These non-GAAP
financial measures should not be considered in isolation or as an
alternative for measures of performance prepared in accordance with
IFRS.
Free Cash Flow
Free cash flow is presented to assist management and investors
in analyzing performance by the Corporation as a measure of
financial liquidity and the capacity of the business to repay debt.
Free cash flow is calculated as adjusted funds flow less capital
expenditures.
|
|
|
|
Three months
ended
September 30
|
Nine months
ended
September 30
|
($millions)
|
2021
|
2020
|
2021
|
2020
|
Net cash provided by
(used in) operating activities
|
$
|
257
|
$
|
(31)
|
$
|
449
|
$
|
186
|
Net change in non-cash
operating working capital items
|
(45)
|
50
|
44
|
(28)
|
Funds flow from
operations
|
212
|
19
|
493
|
158
|
Adjustments:
|
|
|
|
|
Settlement
expense(1)
|
21
|
—
|
21
|
—
|
Payments on onerous
contracts
|
6
|
—
|
18
|
—
|
Contract
cancellation
|
—
|
7
|
—
|
33
|
Adjusted funds
flow
|
$
|
239
|
$
|
26
|
$
|
532
|
$
|
191
|
Capital
expenditures
|
(84)
|
(36)
|
(224)
|
(109)
|
Free cash
flow
|
$
|
155
|
$
|
(10)
|
$
|
308
|
$
|
82
|
(1)
|
During the third
quarter of 2021, the Corporation reached an agreement to settle the
litigation matter commenced in 2014 relating to legacy issues
involving a unit train transloading facility in Alberta. Under the
agreement, the Corporation paid (subsequent to the quarter) the sum
of $21 million in full and final settlement of the claim and the
claim has been discontinued.
|
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 expectation regarding the Christina Lake central plant's facility's oil
processing capacity of approximately 100,000 bbls/day and the
amount of capital investment and timing of such capital investment
required to allow the Corporation to fully utilize this capacity;
the Corporation's commitment to continued debt reduction as a key
component of its capital allocation strategy; the Corporation's
expectation that all available free cash flow generated in the
second half of 2021 will be directed 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 estimate of 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, including vaccine
rollouts; the potential for a temporary suspension of operations
impacted by an outbreak of COVID-19; actions taken by OPEC+ in
relation to supply management; the availability and cost of labour
and goods and services required in the Corporation's operations,
including inflationary pressures; supply chain issues including
transportation delays; the cost and availability of equipment
necessary to our operations; 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
SOURCE MEG Energy Corp.