Strong cash position, proven technology and significant
cost reductions position MEG well to continue highly-economic
growth
All financial figures in Canadian dollars ($ or C$) unless
otherwise noted
CALGARY, Oct. 26, 2017 /CNW/ - MEG Energy Corp. (TSX:MEG)
today reported third quarter 2017 operating and financial results.
Highlights include:
- Quarterly production volumes of 83,008 barrels per day (bpd)
with October production currently averaging approximately 85,000
bpd, reflecting the ramp-up of MEG's eMSAGP growth initiative at
Christina Lake Phase 2B which is proceeding on schedule and under
budget;
- Record-low quarterly net operating costs of $6.00 per barrel supported by non-energy
operating costs of $4.57 per
barrel;
- A 14% reduction in the company's capital budget guidance, from
$590 million to $510 million, with
the majority of the reduction driven by ongoing efficiency
improvements, lower construction costs and improved facility
design;
- Strong operational and financial results contributing to cash
and cash equivalents of $398 million
as of September 30, 2017; and
- A second sequential reduction in MEG's non-energy operating
cost guidance to $4.75 - $5.00 per
barrel, reflecting ongoing efficiency gains and a continued focus
on cost management. The new guidance compares to the previous
guidance of $5.00 - $5.50 per barrel
and is 22% lower than the initial guidance of $5.75 - $6.75 per barrel at its mid-point.
MEG's third quarter 2017 production averaged 83,008 bpd,
compared to 72,448 bpd for the previous quarter. Production for the
third quarter reflected ramp-up from the company's second quarter
turnaround and was partially affected by adverse weather conditions
at the company's Christina Lake
facility and the timing of tying in new wells that are part of the
eMSAGP Phase 2B implementation. The company remains on track to
meet its 2017 average production guidance of 80,000 to 82,000 bpd
and exit the year with production between 86,000 and 89,000
bpd.
"MEG's ongoing technological developments are significantly
changing the way we operate and grow," said Bill McCaffrey, President and Chief Executive
Officer. "These technologies are enabling MEG to meaningfully
reduce its steam-oil ratio, making it possible to reduce capital
requirements for steam and water handling and decrease operating
costs. It also allows for future expansions on a continuous basis
as opposed to project by project, while offering significantly
higher returns and reducing the company's greenhouse gas emissions
intensity."
In those specific well patterns where eMSAGP has already been
deployed, the company is currently seeing a steam-oil ratio of
approximately 1.3, with the freed-up steam being diverted into new
wells to further increase production.
"Our evolving technologies form the basis of the majority of
MEG's future growth," said McCaffrey. "The targeted cost reductions
associated with incremental production growth allow us to continue
to lower our costs on a per barrel basis, and better position the
company to carry out this highly-economic growth going
forward."
For the third quarter of 2017, net operating costs were a
record-low $6.00 per barrel, compared
to $7.42 per barrel in the previous
quarter, due to a per barrel decrease in energy operating costs and
an increase in per barrel power revenue.
Non-energy operating costs were $4.57 per barrel in the third quarter. The
continued decrease in non-energy operating costs compared to the
company's guidance is primarily the result of efficiency gains and
a continued focus on cost management, resulting in lower operations
staffing and materials and services costs.
On a year-to-date basis, non-energy operating costs have
decreased 20% compared to the first nine months of 2016. As a
result of MEG's continued focus on cost control and efficiency
improvements, annual non-energy operating costs for 2017 are now
targeted to be in the range of $4.75 -
$5.00 per barrel, below the original guidance of
$5.75 - $6.75 per barrel and the
adjusted $5.00 - $5.50 per barrel
guidance provided in the company's second quarter 2017
disclosure.
In the third quarter, MEG continued to benefit from increases in
its realized sales price. The average US$WTI price increased 7% in
the third quarter of 2017 compared with the same period of 2016.
However, the WCS differential narrowed by US$3.56 per barrel, or 26%, due to higher demand
for Canadian heavy oil from U.S. Gulf Coast refineries. These
factors increased the company's bitumen realization by
approximately C$9 per barrel compared
to the third quarter of 2016.
Blend sales in the third quarter of 2017 were approximately
6,000 bpd less than production, as these volumes were in transit
over the quarter end, destined for the U.S. Gulf Coast. These sales
volumes will be recognized in the fourth quarter of 2017.
MEG realized adjusted funds flow from operations of $83 million for the third quarter of 2017
compared to adjusted funds flow from operations of $55 million in the previous quarter. The increase
in adjusted funds flow from operations was primarily due to an
increase in bitumen realization and a reduction in net operating
costs.
Capital Investment and Financial Liquidity
Total cash capital investment during the third quarter of 2017
was $103 million. Primarily as a
result of ongoing efficiency improvements, lower construction
costs, improved facility design and the optimization of MEG's
investment profile, the company has reduced its 2017 capital
investment program to $510 million,
compared to the original budget of $590
million. Capital investment in 2017 is primarily directed
towards the company's eMSAGP growth initiative at Christina Lake
Phase 2B, which is proceeding on schedule and under
budget.
"MEG's focus on innovation and cost containment is resulting in
the company being able to achieve better results with lower
investment dollars," said McCaffrey. "We are seeing significant
reductions in our capital needs because of the efficiency
improvements in our reservoir processes and fundamental changes to
our pad and facility designs. As a result, we now anticipate
spending $350 million on the
implementation of eMSAGP on Phase 2B, which comes to $17,500 per flowing barrel, a 13% reduction from
the original estimates of $400
million. This cost reduction contributes to the company's
overall objective of generating higher returns from its capital
investments."
MEG has entered into a series of hedges designed to protect its
capital program against downward oil price movements and mitigate
volatility in cash flow.
For the fourth quarter of 2017, MEG has entered into WTI hedges
on approximately 50% of the company's forecast blend sales with 26%
fixed at US$54.20/bbl and 24% hedged
utilizing costless collars that provide it with downside price
protection at US$47.90/bbl and upside
participation to US$58.60/bbl. The
company has also entered into financial hedges on approximately 45%
of its WCS differential exposure at a price differential to WTI of
US$15.00/bbl and 74% of its
condensate exposure through a combination of financial and physical
transactions at an average price of 99% of WTI.
MEG is also executing its hedge program for 2018. The company
has now entered into WTI hedges on 42,000 bpd of blend sales with
12,500 bpd fixed at US$51.10/bbl and
29,500 bpd hedged utilizing costless collars that provide the
company with downside price protection at US$45.45/bbl and upside participation to
US$54.60/bbl. MEG has also entered
into financial hedges on 29,375 bpd of its WCS differential
exposure at a price differential to WTI of US$14.20/bbl and 12,675 bpd of its condensate
exposure with physical transactions at an average price of 101% of
WTI.
MEG's four-year covenant-lite US$1.4
billion credit facility remains undrawn.
Operational and Financial Highlights
|
|
|
|
|
|
Nine months
ended
September 30
|
2017
|
2016
|
2015
|
($ millions,
except as indicated)
|
2017
|
2016
|
Q3
|
Q2
|
Q1
|
Q4
|
Q3
|
Q2
|
Q1
|
Q4
|
Bitumen production -
bbls/d
|
77,588
|
81,065
|
83,008
|
72,448
|
77,245
|
81,780
|
83,404
|
83,127
|
76,640
|
83,514
|
|
|
|
|
|
|
|
|
|
|
|
Bitumen realization -
$/bbl
|
39.17
|
24.91
|
39.89
|
39.66
|
37.93
|
36.17
|
30.98
|
30.93
|
11.43
|
23.17
|
|
|
|
|
|
|
|
|
|
|
|
Net operating costs -
$/bbl(1)
|
7.26
|
7.89
|
6.00
|
7.42
|
8.43
|
8.24
|
7.76
|
7.43
|
8.53
|
8.52
|
|
|
|
|
|
|
|
|
|
|
|
Non-energy operating
costs - $/bbl
|
4.66
|
5.83
|
4.57
|
4.23
|
5.20
|
4.99
|
5.32
|
5.81
|
6.45
|
5.66
|
|
|
|
|
|
|
|
|
|
|
|
Cash operating
netback - $/bbl(2)
|
24.09
|
10.18
|
26.84
|
22.96
|
22.33
|
21.73
|
16.74
|
16.09
|
(3.71)
|
9.05
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted funds flow
from (used in) operations(3)
|
182
|
(102)
|
83
|
55
|
43
|
40
|
23
|
7
|
(131)
|
(44)
|
|
Per share,
diluted(3)
|
0.63
|
(0.45)
|
0.28
|
0.19
|
0.16
|
0.18
|
0.10
|
0.03
|
(0.58)
|
(0.20)
|
Operating earnings
(loss)(3)
|
(158)
|
(383)
|
(43)
|
(36)
|
(79)
|
(72)
|
(88)
|
(98)
|
(197)
|
(140)
|
|
Per share,
diluted(3)
|
(0.55)
|
(1.70)
|
(0.14)
|
(0.12)
|
(0.29)
|
(0.32)
|
(0.39)
|
(0.43)
|
(0.88)
|
(0.62)
|
Revenue(4)
|
1,680
|
1,301
|
546
|
574
|
560
|
566
|
497
|
513
|
290
|
445
|
Net earnings
(loss)(5)
|
190
|
(124)
|
84
|
104
|
2
|
(305)
|
(109)
|
(146)
|
131
|
(297)
|
|
Per share,
basic
|
0.66
|
(0.55)
|
0.29
|
0.36
|
0.01
|
(1.34)
|
(0.48)
|
(0.65)
|
0.58
|
(1.32)
|
|
Per share,
diluted
|
0.66
|
(0.55)
|
0.28
|
0.35
|
0.01
|
(1.34)
|
(0.48)
|
(0.65)
|
0.58
|
(1.32)
|
|
|
|
|
|
|
|
|
|
|
|
Total cash capital
investment
|
339
|
74
|
103
|
158
|
78
|
63
|
19
|
20
|
35
|
54
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash
equivalents
|
398
|
103
|
398
|
512
|
549
|
156
|
103
|
153
|
125
|
408
|
Long-term
debt
|
4,636
|
4,910
|
4,636
|
4,813
|
4,945
|
5,053
|
4,910
|
4,871
|
4,859
|
5,190
|
(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,
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. For the three and nine months
ended September 30, 2017 and September 30, 2016, 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 Interim Consolidated Statement of Earnings and Comprehensive
Income.
|
(5)
|
Includes a net
unrealized foreign exchange gain of $180.4 million and
$345.1 million on the Corporation's U.S. dollar denominated debt
and U.S. dollar denominated cash and cash equivalents for the three
and nine months ended September 30, 2017, respectively. The net
loss for the three and nine months ended, September 30, 2016
includes a net unrealized foreign exchange loss of $38.7 million
and a net unrealized foreign exchange gain of $267.8 million,
respectively.
|
ADVISORY
Basis of Presentation
MEG prepares its financial statements in accordance with
International Financial Reporting Standards ("IFRS") and presents
financial results in Canadian dollars ($ 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 and charges not incurred in the normal course of
operations, 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
September 30
|
Nine months ended
September 30
|
($000)
|
2017
|
2016
|
2017
|
2016
|
Net cash provided by
(used in) operating activities
|
$
|
7,979
|
$
|
(19,894)
|
$
|
117,397
|
$
|
(175,978)
|
|
Net change in
non-cash operating working capital items
|
51,133
|
45,492
|
28,922
|
76,409
|
Funds flow from (used
in) operations
|
59,112
|
25,598
|
146,319
|
(99,569)
|
|
Adjustments:
|
|
|
|
|
|
|
Contract cancellation
expense
|
18,765
|
-
|
18,765
|
-
|
|
|
Net change in other
liabilities
|
-
|
(4,044)
|
-
|
(5,495)
|
|
|
Payments on onerous
contracts
|
5,089
|
1,049
|
14,691
|
2,395
|
|
|
Decommissioning
expenditures
|
386
|
99
|
1,847
|
1,095
|
Adjusted funds flow
from (used in) operations
|
$
|
83,352
|
$
|
22,702
|
$
|
181,622
|
$
|
(101,574)
|
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, contract cancellation expense, onerous contracts
expense, insurance proceeds and the respective deferred tax impact
on these adjustments. Operating earnings (loss) is reconciled to
"Net earnings (loss)", the nearest IFRS measure, in the table
below.
|
|
|
|
Three months ended
September 30
|
Nine months ended
September 30
|
($000)
|
2017
|
2016
|
2017
|
2016
|
Net earnings
(loss)
|
$
|
83,885
|
$
|
(108,632)
|
$
|
189,755
|
$
|
(123,968)
|
Adjustments:
|
|
|
|
|
|
Unrealized net loss
(gain) on foreign exchange(1)
|
(180,448)
|
38,729
|
(345,116)
|
(267,763)
|
|
Unrealized loss
(gain) on derivative financial liabilities(2)
|
(3,490)
|
(11,367)
|
(7,346)
|
(5,362)
|
|
Unrealized loss
(gain) on commodity risk management(3)
|
57,470
|
(32,207)
|
(19,353)
|
(11,736)
|
|
Contract cancellation
expense(4)
|
18,765
|
-
|
18,765
|
-
|
|
Onerous contracts
expense(5)
|
(27)
|
18,057
|
5,681
|
31,483
|
|
Insurance
proceeds
|
(183)
|
-
|
(183)
|
-
|
|
Deferred tax expense
(recovery) relating to these adjustments
|
(18,543)
|
7,491
|
218
|
(5,763)
|
Operating earnings
(loss)
|
$
|
(42,571)
|
$
|
(87,929)
|
$
|
(157,579)
|
$
|
(383,109)
|
(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)
|
During the third
quarter of 2017, the Corporation recognized a contract cancellation
expense of $18.8 million relating to the termination of a long-term
marketing transportation contract that had not yet
commenced.
|
(5)
|
Onerous contracts
expense primarily includes changes in estimated future cash flow
sublease recoveries related to the onerous office lease provision
for the Corporation's office building lease
contracts.
|
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, results securing access to
markets and transportation infrastructure; 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
SEDAR website which is available 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 Third Quarter 2017 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 8:30 a.m. Mountain
Time (10:30 a.m. Eastern Time)
on Thursday, October 26, 2017. The
North American toll-free conference call number is 1-888-231-8191.
The international conference call number is 647-427-7450.
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
Davis
Sheremata
Senior Advisor, External Communications
587-233-8311
davis.sheremata@megenergy.com
SOURCE MEG Energy Corp.