Increases 2018 production guidance and lowers non-energy
operating cost per barrel guidance; remains on-track to reach
113,000 bpd in 2020
All financial figures in Canadian dollars ($ or C$) unless
otherwise noted
CALGARY, Aug. 2, 2018 /CNW/ - MEG Energy Corp.
(TSX:MEG) today reported second quarter 2018 operating and
financial results. Highlights include:
- Quarterly production volumes of 71,325 barrels per day, while
completing planned maintenance activities. With strong first half
production, annual production guidance has been revised higher to
87,000 to 90,000 barrels per day (bpd), from 85,000 to 88,000
bpd;
- Record low per barrel net operating costs of $5.64, including non-energy operating costs of
$5.47, which were impacted by lower
sales volumes in the quarter. Annual non-energy operating cost
guidance has been reduced by 5% to $4.50 to $5.00 per
barrel, from $4.75 to $5.25 per barrel to reflect strong cost
performance to-date;
- Adjusted funds flow from operations of $18 million, impacted by lower sales volumes due
to turnaround activities, realized losses on commodity derivatives,
and mark-to-market, unrealized cash-settled stock-based
compensation;
- Total cash capital investment of $183
million in the quarter, primarily directed to planned
turnaround activities and advancing key growth projects. The 2018
capital plan has been revised to $670
million from the previously announced $700 million, to reflect improved capital cost
efficiencies and strong operational results on the Phase
2B eMSAGP implementation;
and
- Cash and cash equivalents of $564
million, MEG's covenant-lite US$1.4
billion facility remains undrawn.
During the second quarter of 2018, MEG completed a large-scale
turnaround at Christina Lake Phase 2B, lasting 33 days. Production in the quarter
averaged 71,325 bpd, which was in-line with the second quarter of
2017, and 23% lower than the first quarter of 2018. The lower
quarter-over-quarter production is the result of planned
maintenance activities.
Subsequent to the quarter, MEG completed essentially all
investment required for the application of eMSAGP to the Phase
2B producing assets. This led to
strong production at Christina
Lake during the month of July, averaging over 98,000 bpd.
The Company has increased its annual production guidance to 87,000
to 90,000 bpd, and year-end exit production is anticipated to
average just over 100,000 bpd.
"MEG executed the largest turnaround in its history during the
second quarter. The value of our diligent approach to regular plant
maintenance was demonstrated as the turnaround confirmed the
overall integrity of the plant," said Harvey Doerr, Interim President and CEO. "The
turnaround allowed us to tie-in and modify a number of pieces of
equipment, which enable us to reliably run at higher production
levels. We saw record production day rates in excess of 100,000 bpd
for several days in July as new Phase 2B eMSAGP wells were brought
on-stream."
MEG's blend sales realization averaged $62.32 per barrel in the second quarter of 2018,
22% higher than the first quarter of 2018. The higher blend sales
realization was the result of stronger benchmark crude oil prices
and tighter differentials. The Company sold approximately 32,000
bpd of blend into the U.S. Gulf Coast during the second quarter,
reflecting apportionment of approximately 46% on the Enbridge
Mainline system. The majority of the Company's remaining barrels
were sold in Edmonton. MEG's
bitumen realization averaged $47.20
per barrel in the second quarter of 2018, 34% higher than the first
quarter of 2018.
"MEG's marketing strategy has been focused on diversifying our
markets, intended to minimize risk and maximize the value received
for our barrels. Our rail loading and strategic storage facilities
have helped to mitigate the impact of apportionment, and together
with our commitment on the Flanagan South and Seaway pipelines,
support better price realizations," said Doerr. "However, pipeline
apportionment is expected to continue to impact the industry in the
short term. We continue to be supportive of Enbridge's initiative
to address the nomination methodology on the Mainline system, which
should have a positive impact. In the medium term, completion of
the Line 3 expansion will further enhance MEG's ability to take
advantage of its commitment on the Flanagan South/Seaway, which
doubles to 100,000 bpd in mid-2020."
Transportation costs for the second quarter of 2018 were
$8.28 per barrel, 20% higher than the
second quarter of 2017, and 38% higher than the first quarter of
2018. The higher transportation expense reflects the first full
quarter impact of the recent sale of the Company's 50% share in the
Access Pipeline and 100% of Stonefell Terminal, as well as lower
sales volumes due to the plant turnaround.
Capital and Operational Update
Total cash capital investment in the quarter was $183 million, with funds directed towards planned
turnaround activities, implementation of Phase 2B eMSAGP, advancement of the eMVAPEX pilot, and
continued work on the Phase 2B
brownfield expansion. During the quarter, MEG invested $22 million on the Phase 2B eMSAGP implementation. All spending on the
project was completed subsequent to the quarter, with total costs
coming in at $340 million. The final
costs were lower than both the original capital estimate of
$400 million and the revised estimate
of $350 million. The 2018 capital
program has been reduced to $670
million from the previously announced $700 million to reflect ongoing capital cost
efficiencies.
MEG's hedging philosophy over the last two years has been
focused on protecting its capital program. With current cash
reserves, higher commodity prices and lower anticipated levels of
capital spend in 2019, the Company expects to hedge a substantially
lower percentage of its barrels going forward.
As a result of a review of the Company's marketing assets, MEG
has engaged TD Securities Inc. to review strategic
alternatives with respect to its proprietary HI-Q® partial
upgrading technology. This technology has the potential to
eliminate the use of diluent for bitumen transport. MEG is seeking
a third-party transaction, which will take HI-Q® to commerciality
while retaining access to the technology and will not require the
Company to invest additional capital.
Net operating costs for the second quarter of 2018 averaged
$5.64 per barrel, which is 24% and 6%
lower than the second quarter of 2017 and first quarter of 2018,
respectively. The strong per barrel net operating costs were
achieved despite lower bitumen sales volumes in the quarter. The
ongoing reduction in net operating costs reflects efficiency gains
and continued focus on cost management. Annual non-energy operating
cost guidance has been reduced to $4.50 to $5.00 per
barrel, from $4.75 to $5.25 per barrel, to account for strong cost
performance year-to-date.
Adjusted Funds Flow
MEG realized adjusted funds flow from operations of $18 million for the second quarter of 2018,
compared to $55 million in the second
quarter of 2017, and $83 million in
the first quarter of 2018. Higher crude oil prices in the quarter
were more than offset by lower production volumes, a realized loss
on commodity derivatives and mark-to-market unrealized cash-settled
stock-based compensation expense. Realized losses on commodity
derivatives totalled $89 million, as
crude oil benchmark prices exceeded the Company's crude oil
contract prices.
Mark-to-market on the unrealized portion of cash-settled
stock-based compensation reduced second quarter adjusted funds flow
by $14 million, or $0.05 per share. MEG's stock price increased
approximately 140% from March 31,
2018 to June 30, 2018,
resulting in an increase in the fair value of the cash-settled
units outstanding. MEG adopted cash-settled stock-based
compensation for a portion of its long-term incentive (LTI) program
for 2016 and 2017, which vest over a three-year period. The
Company's LTI plans are designed to align compensation to corporate
performance and are linked to the Company's stock price
performance.
Outlook
The search committee of the Board has identified, interviewed
and subsequently shortlisted a small number of qualified candidates
for the role of permanent CEO. The Board expects to make a final
decision in the third quarter of 2018.
"With 100,000 bpd in reach, MEG remains firmly on-track to
deliver on our Vision 20/20. As the turnaround is now behind us,
and spending on Phase 2B eMSAGP is
essentially complete, capital in the second half of the year will
be primarily focused on the Phase 2B
brownfield expansion. Given our strong cash balance of $564 million and significantly higher cash flow
anticipated in the second half of 2018, we are well-positioned to
internally fund our capital plans to 2020," said Doerr. "While we
have realized significant improvements across our business, we
continue to look for ways to further advance our technology,
improve our highly competitive overall cost position and maximize
the revenue we receive for our barrels."
Operational and Financial Highlights
|
|
|
|
|
|
Six months
ended
June
30
|
2018
|
2017
|
2016
|
($ millions,
except as indicated)
|
2018
|
2017
|
Q2
|
Q1
|
Q4
|
Q3
|
Q2
|
Q1
|
Q4
|
Q3
|
Bitumen production -
bbls/d
|
82,205
|
74,883
|
71,325
|
93,207
|
90,228
|
83,008
|
72,448
|
77,245
|
81,780
|
83,404
|
|
|
|
|
|
|
|
|
|
|
|
Bitumen realization -
$/bbl
|
40.67
|
38.80
|
47.20
|
35.31
|
48.30
|
39.89
|
39.66
|
37.93
|
36.17
|
30.98
|
|
|
|
|
|
|
|
|
|
|
|
Net operating costs -
$/bbl(1)
|
5.82
|
7.92
|
5.64
|
5.98
|
5.86
|
6.00
|
7.42
|
8.43
|
8.24
|
7.76
|
|
|
|
|
|
|
|
|
|
|
|
Non-energy operating
costs - $/bbl
|
4.96
|
4.71
|
5.47
|
4.55
|
4.53
|
4.57
|
4.23
|
5.20
|
4.99
|
5.32
|
|
|
|
|
|
|
|
|
|
|
|
Cash operating
netback - $/bbl(2)
|
19.43
|
22.66
|
18.53
|
20.16
|
33.83
|
26.84
|
22.96
|
22.33
|
21.73
|
16.74
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted funds flow
from operations(3)
|
102
|
98
|
18
|
83
|
192
|
83
|
55
|
43
|
40
|
23
|
|
Per share,
diluted(3)
|
0.34
|
0.35
|
0.06
|
0.28
|
0.65
|
0.28
|
0.19
|
0.16
|
0.18
|
0.10
|
Operating earnings
(loss)(3)
|
(88)
|
(115)
|
(70)
|
(18)
|
44
|
(43)
|
(36)
|
(79)
|
(72)
|
(88)
|
|
Per share,
diluted(3)
|
(0.30)
|
(0.40)
|
(0.24)
|
(0.06)
|
0.15
|
(0.14)
|
(0.12)
|
(0.29)
|
(0.32)
|
(0.39)
|
Revenue(4)
|
1,410
|
1,143
|
689
|
721
|
755
|
576
|
584
|
560
|
566
|
497
|
Net earnings
(loss)
|
(38)
|
106
|
(179)
|
141
|
(1)
|
84
|
104
|
2
|
(305)
|
(109)
|
|
Per share,
basic
|
(0.13)
|
0.37
|
(0.61)
|
0.48
|
(0.00)
|
0.29
|
0.36
|
0.01
|
(1.34)
|
(0.48)
|
|
Per share,
diluted
|
(0.13)
|
0.37
|
(0.61)
|
0.47
|
(0.00)
|
0.28
|
0.35
|
0.01
|
(1.34)
|
(0.48)
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cash capital
investment
|
330
|
236
|
183
|
148
|
163
|
103
|
158
|
78
|
63
|
19
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash
equivalents
|
564
|
512
|
564
|
675
|
464
|
398
|
512
|
549
|
156
|
103
|
Long-term
debt
|
3,607
|
4,813
|
3,607
|
3,543
|
4,637
|
4,636
|
4,813
|
4,945
|
5,053
|
4,910
|
|
|
(1)
|
Net operating
costs include energy and non-energy operating costs, reduced by
power revenue.
|
|
|
(2)
|
Cash operating
netback is calculated by deducting the related diluent expense,
blend purchases, transportation, operating expenses, royalties and
realized commodity risk management gains (losses) from proprietary
blend revenues and power revenues, on a per barrel of bitumen sales
volume basis.
|
|
|
(3)
|
Adjusted funds
flow from (used in) operations, operating earnings (loss) and the
related per share amounts do not have standardized meanings
prescribed by IFRS and therefore may not be comparable to similar
measures used by other companies. The non-GAAP measure of adjusted
funds flow from (used in) operations is reconciled to net cash
provided by (used in) operating activities and the non-GAAP measure
of operating earnings (loss) is reconciled to net earnings (loss)
in accordance with IFRS under the heading "NON-GAAP MEASURES" and
discussed further in the "ADVISORY" section.
|
|
|
(4)
|
The total of
petroleum revenue, net of royalties and other revenue as presented
on the consolidated statement of earnings and comprehensive income.
Effective January 1, 2018, petroleum revenues are presented on a
gross basis as they represent separate performance obligations, as
discussed in the "NEW ACCOUNTING STANDARDS" section of MEG's
"Management Discussion and Analysis" dated August 1, 2018. Prior
quarters have been revised as applicable to reflect the new
presentation.
|
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: net
marketing activity, funds flow from (used in) operations, adjusted
funds flow from (used in) operations, operating earnings (loss),
operating cash flow and total debt 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.
Funds Flow From (Used in) Operations and Adjusted Funds Flow
From (Used in) Operations
Funds flow from (used in) operations and adjusted funds flow
from (used in) operations are non-GAAP measures utilized by the
Corporation to analyze operating performance and liquidity. Funds
flow from (used in) operations excludes the net change in non-cash
operating working capital while the IFRS measurement "net cash
provided by (used in) operating activities" includes these items.
Adjusted funds flow from (used in) operations excludes the net
change in non-cash operating working capital, realized gain on
foreign exchange derivatives not considered part of ordinary
continuing operating results, payments on onerous contracts and
decommissioning expenditures, while the IFRS measurement "net cash
provided by (used in) operating activities" includes these items.
Funds flow from (used in) operations and adjusted funds flow from
(used in) operations are not intended to represent net cash
provided by (used in) operating activities calculated in accordance
with IFRS. Funds flow from (used in) operations and adjusted funds
flow from (used in) operations are reconciled to net cash provided
by (used in) operating activities in the table below.
|
|
|
|
Three months ended
June 30
|
Six months ended
June 30
|
($000)
|
2018
|
2017
|
2018
|
2017
|
Net cash provided by
(used in) operating activities
|
$
|
65,243
|
$
|
63,612
|
$
|
183,269
|
$
|
109,418
|
|
Net change in
non-cash operating working capital items
|
(51,836)
|
(14,024)
|
(59,972)
|
(22,211)
|
Funds flow from (used
in) operations
|
13,407
|
49,588
|
123,297
|
87,207
|
Adjustments:
|
|
|
|
|
|
Realized gain on
foreign exchange derivatives(1)
|
-
|
-
|
(35,362)
|
-
|
|
Payments on onerous
contracts
|
4,236
|
5,468
|
10,244
|
9,602
|
|
Decommissioning
expenditures
|
750
|
39
|
3,371
|
1,461
|
Adjusted funds flow
from (used in) operations
|
$
|
18,393
|
$
|
55,095
|
$
|
101,550
|
$
|
98,270
|
|
|
(1)
|
A gain related to
the settlement of forward currency contracts to manage the foreign
exchange risk on those Canadian dollar denominated proceeds related
to the sale of assets designated for U.S. dollar denominated
long-term debt repayment.
|
Operating Earnings (Loss)
Operating earnings (loss) is a non-GAAP measure which the
Corporation uses as a performance measure to provide comparability
of financial performance between periods by excluding non-operating
items. Operating earnings (loss) is defined as net earnings (loss)
as reported, excluding unrealized foreign exchange gains and
losses, unrealized gains and losses on derivative financial
instruments, unrealized gains and losses on commodity risk
management, realized gains and losses on foreign exchange
derivatives, gain on asset dispositions, onerous contracts expense,
and the respective deferred tax impact on these adjustments.
Operating earnings (loss) is reconciled to "Net earnings (loss)",
the nearest IFRS measure.
|
|
|
|
Three months ended
June 30
|
Six months ended
June 30
|
($000)
|
2018
|
2017
|
2018
|
2017
|
Net earnings
(loss)
|
$
|
(178,570)
|
$
|
104,282
|
$
|
(37,997)
|
$
|
105,870
|
Adjustments:
|
|
|
|
|
|
Unrealized loss
(gain) on foreign exchange(1)
|
62,377
|
(127,961)
|
203,675
|
(164,668)
|
|
Unrealized loss
(gain) on derivative financial liabilities(2)
|
(110)
|
(1,615)
|
2,866
|
(3,856)
|
|
Unrealized loss
(gain) on commodity risk management(3)
|
61,288
|
(17,224)
|
119,320
|
(76,823)
|
|
Realized foreign
exchange loss (gain) on foreign exchange derivatives(4)
|
-
|
-
|
(35,362)
|
-
|
|
Gain on asset
dispositions(5)
|
-
|
-
|
(318,398)
|
-
|
|
Onerous contracts
expense
|
145
|
3,333
|
789
|
5,708
|
|
Deferred tax expense
(recovery) relating to these adjustments
|
(15,304)
|
3,529
|
(23,082)
|
18,761
|
Operating earnings
(loss)
|
$
|
(70,174)
|
$
|
(35,656)
|
$
|
(88,189)
|
$
|
(115,008)
|
|
|
(1)
|
Unrealized net
foreign exchange gains and losses result from the translation of
U.S. dollar denominated long-term debt and cash and cash
equivalents using period-end exchange rates.
|
|
|
(2)
|
Unrealized gains
and losses on derivative financial liabilities result from the
interest rate floor on the Corporation's long-term debt and
interest rate swaps entered into to effectively fix a portion of
its variable rate long-term debt.
|
|
|
(3)
|
Unrealized gains
or losses on commodity risk management contracts represent the
change in the mark-to-market position of the unsettled commodity
risk management contracts during the period.
|
|
|
(4)
|
A gain related to
the settlement of forward currency contracts to manage the foreign
exchange risk on those Canadian dollar denominated proceeds related
to the sale of assets designated for U.S. dollar denominated
long-term debt repayment.
|
|
|
(5)
|
A gain related to
the sale of the Corporation's 50% interest in the Access
Pipeline.
|
Forward-Looking Information
This document may contain forward-looking information including
but not limited to: expectations of future production, revenues,
expenses, cash flow, operating costs, steam-oil ratios, pricing
differentials, reliability, profitability and capital investments;
estimates of reserves and resources; anticipated reductions in
operating costs as a result of optimization and scalability of
certain operations; and anticipated sources of funding for
operations and capital investments. Such forward-looking
information is based on management's expectations and assumptions
regarding future growth, results of operations, production, future
capital and other expenditures, plans for and results of drilling
activity, environmental matters, 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 include, but are not limited to: risks associated with
the oil and gas industry, for example, the securing of adequate
supplies and access to markets and transportation infrastructure
and the commitments and risks therein; availability of capacity on
the electricity transmission grid; uncertainty of reserve and
resource estimates; uncertainty associated with estimates and
projections relating to production, costs and revenues; health,
safety and environmental risks; risks of legislative and regulatory
changes to, amongst other things, tax, land use, royalty and
environmental laws; assumptions regarding and the volatility of
commodity prices, interest rates and foreign exchange rates, and,
risks and uncertainties related to 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; risks and
uncertainties associated with 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;
risks and uncertainties related to the timing of completion,
commissioning, and start-up, of MEG's 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; and uncertainties arising in
connection with any future disposition of assets.
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 document is
expressly qualified in its entirety by the foregoing cautionary
statements. Unless otherwise stated, the forward-looking
information included in this document is made as of the date of
this document and MEG assumes no obligation to update or revise any
forward-looking information to reflect new events or circumstances,
except as required by law.
A full version of MEG's Second Quarter Report to Shareholders,
including unaudited financial statements, is available at
www.megenergy.com/investors and at www.sedar.com.
A conference call will be held to review the operating and
financial results at 8 a.m. Mountain Time (10 a.m. Eastern Time) on Thursday, August 2,
2018. The North American toll-free conference call number is
1-888-390-0546. The international conference call number is
587-880-2171.
A recording of the call will be available by 12 noon
Mountain Time (2 p.m. Eastern
Time) on August 2, 2018 on the Company's website
at www.megenergy.com/investors/presentations-and-events. A phone
recording will also be available until 9:59 p.m. Mountain
Time (11:59 p.m. Eastern Time)
on September 1, 2018. To access the phone recording, dial
toll-free (+1) 888-390-0541 or local 416-764-8677 and enter the
pass code 242663.
MEG Energy Corp. is focused on sustainable in situ oil sands
development and production in the southern Athabasca oil sands region of Alberta, Canada. MEG is actively developing
enhanced oil recovery projects that utilize SAGD extraction
methods. MEG's common shares are listed on the Toronto Stock
Exchange under the symbol "MEG".
For further information, please contact:
Investors
Helen
Kelly
Director, Investor Relations
403-767-6206
helen.kelly@megenergy.com
Media
Megan Hjulfors
Senior Advisor, Investor Relations
403-767-6211
megan.hjulfors@megenergy.com
SOURCE MEG Energy Corp.