MEG Energy reports record quarterly, annual and exit-rate production volumes
Production and marketing strategies to reach major milestones in 2013
CALGARY, Jan. 31, 2013 /CNW/ – MEG Energy Corp. today reported fourth
quarter and full-year 2012 operational and financial results.
Highlights include:
-- Record annual and exit production volumes, exceeding 2012
guidance;
-- Record quarterly production and low operating costs contribute
to very strong fourth quarter netbacks;
-- Agreements in place to enable substantial volumes to be
transported by rail and barge to high-value markets, providing
the option to bypass congested pipeline infrastructure;
-- Fabrication and delivery to site of all major components of the
Christina Lake Phase 2B project, with start-up scheduled in the
second half of 2013;
-- Regulatory approval for deployment of proprietary eMSAGP
production technology to additional well-pads as part of the
RISER production enhancement initiative; and
-- Independent evaluation increased proved reserves by more than
80% year-over-year, as project developments and resource
definition advanced.
“Record production levels and low operating costs contributed to a
netback of $34.44, which we believe places MEG among the best in the
industry for the value we get out of every barrel,” said Bill
McCaffrey, MEG President and Chief Executive Officer. ”To further build
on that strong performance, we are taking major strategic steps in 2013
to both increase production and improve market access. Starting
mid-year, we expect to market volumes to the U.S. Gulf Coast through
agreements already in place for rail and barge transportation, allowing
us to directly access these higher-value markets.”
Production during the fourth quarter of 2012 was 32,292 barrels per day
(bpd), MEG’s highest quarterly volume to date. Comparative fourth
quarter 2011 production averaged 30,032 bpd. Annual production for
2012 averaged 28,773 bpd, an increase of 8% over 2011 volumes of 26,605
bpd, marking MEG’s fourth consecutive year of production gains.
Net operating costs for the fourth quarter of 2012 were $8.95 per
barrel, expected to be among the lowest in the industry for the period.
Comparable fourth quarter 2011 results, the best in MEG’s history, were
$8.50 per barrel. The difference in net operating costs is primarily
due to lower per barrel power sales and higher non-energy operating
costs during the fourth quarter of 2012 compared to the fourth quarter
of 2011. Non-energy operating costs for 2012 were $9.71 per barrel,
beating MEG’s 2012 target of $10 to $12 per barrel.
Cash flow from operations for the fourth quarter of 2012 was $56.1
million ($0.27 per share, diluted) compared to cash flow of $121.6
million ($0.61 per share, diluted) in the fourth quarter of 2011. The
decrease was primarily due to lower bitumen realizations, higher
general and administrative expense and higher interest expense,
partially offset by higher production.
MEG recorded a net loss of $18.7 million ($0.09 per share, diluted) for
the fourth quarter of 2012 compared to net income of $91.1 million
($0.46 per share, diluted) in the fourth quarter of 2011. Fourth
quarter 2012 results included a net foreign exchange loss of $21.1
million, primarily arising from the translation of MEG’s U.S. dollar
denominated debt and U.S. dollar cash and cash equivalents. For the
comparable period in 2011, there was a net foreign exchange gain of
$33.7 million.
Operating earnings, which are adjusted to exclude items that are not
indicative of operating performance, were recorded as a loss of $0.5
million in the fourth quarter of 2012 ($0.00 per share, diluted)
compared to earnings of $57.8 million ($0.29 per share, diluted) in the
same period of 2011. Operating earnings were impacted by the same
factors that affected cash flow from operations.
Capital and growth strategy
Full-year capital investment for 2012 was approximately $1.6 billion,
slightly below MEG’s forecast of $1.75 billion due to a shift in timing
of capital investments. The majority of the 2012 budget was invested in
MEG’s strategic plan to support increasing production capacity tenfold
to 260,000 bpd in 2020.
Investments in 2012 were focused primarily on the RISER initiative
($234.3 million) to drive near-term production increases and Christina
Lake Phase 2B ($631.5 million), which is targeted to more than double
MEG’s production capacity in the second half of 2013. All materials and
project modules associated with Phase 2B have been delivered, with
on-site construction continuing. With the continuing deployment of
RISER and the planned completion of Phase 2B in the second half of
2013, MEG is targeting a 16% increase in annual production to
approximately 32,000 to 35,000 bpd, with investments this year
supporting longer-term targets of 80,000 bpd in early 2015.
In addition to ongoing investments in growth initiatives, MEG has also
targeted investments to improve market access with the goal of
mitigating differentials to drive higher sales prices and related cash
flow in the near term. MEG has recently entered into agreements for
rail terminal capacity accessible by direct pipeline connections to the
company’s Stonefell Terminal, as well as leasing agreements for barges
to provide transportation to high-value markets throughout the U.S.
Gulf Coast via US inland waterways.
These market access options are expected to allow MEG to begin bypassing
U.S. pipeline congestion and shift product pricing from the discounted
Edmonton and mid-continent markets to higher value markets on the east
coast and U.S. Gulf Coast. Contracted capacity on rail terminals and
barges are expected to accommodate MEG’s mid-2013 production levels.
Additional contracted capacity on the Flanagan South pipeline,
providing further U.S. Gulf Coast access, is expected to be available
in mid-2014. This combination of pipeline access, along with continuing
options for rail and barge transportation, is expected to provide MEG
with reliable access to the best available pricing as the company’s
production grows.
Financial Condition and Liquidity
MEG’s cash and short-term investment balance was $2.0 billion as at
December 31, 2012 compared to $1.6 billion as at December 31, 2011.
Long-term debt increased to $2.5 billion as at December 31, 2012 from
$1.8 billion as at December 31, 2011. On December 28, 2012, MEG issued
24.2 million common shares at a price of $33.00 per share for net
proceeds of $774.8 million. 12.1 million common shares were issued
through a public bought deal financing while the remaining 12.1 million
common shares were issued on a private placement basis.
“The December equity issue adds significant strength to our financial
foundation, with the proceeds largely going toward the deployment of
RISER to Phases 2 and 2B,” said McCaffrey. “In combination with
well-structured debt, the added cash flow we expect to generate will
help fund a meaningful portion of our future growth.”
In addition to MEG’s $2.0 billion in cash and short-term investments as
at December 31, 2012, MEG’s capital resources also include an undrawn
US$1.0 billion revolving credit facility.
Reserves update
GLJ Petroleum Consultants Ltd. (“GLJ”), an independent reservoir
engineering firm, has completed an evaluation of MEG’s bitumen reserves and resources effective as of December 31, 2012. Proved bitumen reserves increased more than 80% to an estimated 1.3 billion barrels from
approximately 700 million barrels at December 31, 2011, while proved
plus probable reserves increased to 2.6 billion barrels from 2.1 billion barrels. GLJ’s
estimate of contingent resources (on a best estimate basis) was approximately 3.4 billion barrels,
compared to 3.8 billion barrels a year earlier, reflecting the
continued de-risking of MEG’s assets through the conversion of
contingent resources to the reserves category.
“MEG’s large, high-quality resource base is the foundation of our growth
strategy,” said McCaffrey. “This most recent evaluation, supported by
our ongoing project development, places MEG among the largest holders
of proved and proved-plus-probable reserves in the Canadian oil
industry.”
The pre-tax net present value of the future net cash flows of the proved
reserves and of the proved plus probable reserves, discounted at 10% per annum, were $10.5 billion and $16.8 billion,
respectively. A summary of GLJ’s report, along with important
information regarding net present value calculations and the
classification of reserves and contingent resources is included in MEG’s Fourth Quarter Report to Shareholders (the “4Q
Report”) under the heading “Reserves and Resources”.
Operational and Financial Highlights
The following table summarizes selected operational and financial
information for the periods ended:
Three months ended Year ended
December 31 December 31
2012 2011 2012 2011
Bitumen
production -
bpd 32,292 30,032 28,773 26,605
Steam to oil
ratio 2.4 2.3 2.4 2.4
West Texas
Intermediate
(WTI)
US$/bbl 88.18 94.06 94.21 95.12
Differential
- WTI/Blend
% 29.9% 18.2% 31.2% 23.5%
Bitumen
realization
- $/bbl 45.67 67.99 46.93 58.74
Net
operating
costs(1)-
$/bbl 8.95 8.50 9.98 10.96
Cash
operating
netback(2) -
$/bbl 34.44 54.64 34.18 43.15
Capital cash
investment -
$000 494,916 268,814 1,598,514 928,921
Net income
(loss) -
$000 (18,740) 91,118 52,569 63,837
Per share, (0.09) 0.46 0.26 0.32
diluted
Operating
earnings
(loss) -
$000(3) (538) 57,833 21,242 109,255
Per share,
diluted(3) 0.00 0.29 0.11 0.55
Cash flow
from
operations -
$000(3) 56,106 121,608 212,514 304,627
Per share,
diluted(3) 0.27 0.61 1.06 1.54
Cash and
short-term
investments
- $000 2,007,841 1,647,069 2,007,841 1,647,069
Long-term
debt - $000 2,488,609 1,751,539 2,488,609 1,751,539
Bitumen Reserves and Contingent Resources (millions of barrels, before
royalties)
Proved (1P)
Reserves(4) 1,284 708
Probable
Reserves(5) 1,360 1,352
Proved Plus
Probable
(2P)
Reserves(4)
(5) 2,644 2,060
Best
Estimate
Contingent
Resources
(2C)(6)(7)
(8) 3,420 3,818
(1) Net operating costs include energy and non-energy operating costs,
reduced by power sales for the period. Please refer to Cash
Operating Netbacks discussed further under the heading "RESULTS OF
OPERATIONS" within the 4Q Report.
(2) Cash operating netbacks are calculated by deducting the related
royalties and diluents, transportation, operating costs and
realized gains/losses on financial derivatives from bitumen sales
revenues, on a per barrel basis. Please refer to note 3 of the
Cash Operating Netbacks table under the heading "RESULTS OF
OPERATIONS" within the 4Q Report.
(3) Operating earnings (loss), cash flow from operations 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 Corporation uses these
non-IFRS measurements for its own performance measures and to
provide its shareholders with a measurement of the Corporation's
ability to internally fund future capital investments. These
non-IFRS measurements are reconciled to net income (loss) and net
cash provided by operating activities in accordance with IFRS
under the heading "NON-IFRS MEASUREMENTS" within the 4Q Report.
(4) "Proved Reserves" are those reserves that can be estimated with a
high degree of certainty to be recoverable. It is likely that the
actual remaining quantities recovered will exceed the estimated
proved reserves. Proved Reserves are also referred to as "1P
Reserves".
(5) "Probable Reserves" are those additional reserves that are less
certain to be recovered than Proved Reserves. It is equally likely
that the actual remaining quantities recovered will be greater or
less than the sum of the estimated proved plus probable reserves.
Proved plus probable reserves are also referred to as "2P
Reserves".
(6) "Contingent Resources" are those quantities of petroleum
estimated, as of a given date, to be potentially recoverable from
known accumulations using established technology or technology
under development, but which are not currently considered to be
commercially recoverable due to one or more contingencies. Such
contingencies include further reservoir delineation, additional
facility and reservoir design work, submission of regulatory
applications and the receipt of corporate approvals. It is also
appropriate to classify as contingent resources the estimated
discovered recoverable quantities associated with a project in the
early evaluation stage. Contingent resources are further
classified in accordance with the level of certainty associated
with the estimates and may be sub-classified based on project
maturity and/or characterized by their economic status. There is
no certainty that it will be commercially viable to produce any
portion of the contingent resources.
(7) There are three categories in evaluating Contingent Resources: Low
Estimate, Best Estimate and High Estimate. The resource numbers
presented all refer to the Best Estimate category. Best Estimate
is a classification of resources described in the Canadian Oil and
Gas Evaluation (COGE) Handbook as being considered to be the best
estimate of the quantity that will actually be recovered. It is
equally likely that the actual remaining quantities recovered will
be greater or less than the Best Estimate. If probabilistic
methods are used, there should be a 50% probability (P50) that the
quantities actually recovered will equal or exceed the Best
Estimate. Best Estimate Contingent Resources are also referred to
as "2C Resources".
(8) These volumes are the arithmetic sums of the Best Estimate
Contingent Resources for Christina Lake, Surmont and the Growth
Properties.
A full version of the Fourth Quarter Report, including unaudited
financial statements, is available in the Investors section of www.megenergy.com and at www.sedar.com.
A conference call will be held to review the fourth quarter results and
discuss MEG’s strategy at 7:30 a.m. Mountain Time (9:30 a.m. Eastern
Time) on Thursday, January 31, 2013. The U.S./Canada toll-free
conference call number is 1 888-231-8191.
Forward-Looking Information
This document may contain forward-looking information including but not
limited to: expectations of future production, revenues, cash flow,
pricing differentials and capital investments; estimates of reserves
and resources; the anticipated capital requirements, development plans,
timing for completion, capacities and performance of the RISER
initiative, the Stonefell Terminal, third party barging and rail
facilities and the future phases and expansions of the Christina Lake
project; and the anticipated sources and sufficiency of funding for
MEG’s future growth. Such forward-looking information is based on
management’s expectations and assumptions regarding future growth,
results of operations, production, future capital and other
expenditures (including the amount, nature and sources of funding
thereof), plans for and results of drilling activity, environmental
matters, 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 (e.g.
operational risks and delays in the development, exploration or
production associated with MEG’s projects; the securing of adequate
supplies and access to markets and transportation infrastructure; the
availability of capacity on the electrical 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; 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 and foreign exchange rates; and risks and
uncertainties associated with securing and maintaining the necessary
regulatory approvals and financing to proceed with the continued
expansion of the Christina Lake project and the development of the
Corporation’s other projects and facilities. 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. 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
the Corporation assumes no obligation to update or revise any
forward-looking information to reflect new events or circumstances,
except as required by law. For more information regarding
forward-looking information see “Notice Regarding Forward Looking
Information”, “Risk Factors” and “Regulatory Matters” within MEG’s
Annual Information Form dated March 28, 2012 (the “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 (www.sedar.com) or by contacting MEG’s investor relations department.
Estimates of Reserves and Resources
This document contains references to estimates of the Corporation’s
reserves and contingent resources. For supplemental information
regarding the classification and uncertainties related to MEG’s
estimated reserves and resources please see “Independent Reserve and
Resource Evaluation” in the AIF.
Non-IFRS Financial Measures
This document includes references to financial measures commonly used in
the crude oil and natural gas industry, such as operating earnings
(loss), cash flow from operations and cash operating netback. These
financial measures are not defined by IFRS as issued by the
International Accounting Standards Board and therefore are referred to
as non-IFRS measures. The non-IFRS measures used by MEG may not be
comparable to similar measures presented by other companies. MEG uses
these non-IFRS measures to help evaluate its performance. Management
considers operating earnings (loss) and cash operating netback
important measures as they indicate profitability relative to current
commodity prices. Management uses cash flow from operations to measure
MEG’s ability to generate funds to finance capital expenditures and
repay debt. These non-IFRS measures should not be considered as an
alternative to or more meaningful than net income or net cash provided
by operating activities, as determined in accordance with IFRS, as an
indication of MEG’s performance. The non-IFRS operating earnings (loss)
and cash operating netback measures are reconciled to net income
(loss), while cash flow from operations is reconciled to net cash
provided by operating activities, as determined in accordance with
IFRS, under the heading “Non-IFRS Measurements” in MEG’s 4Q Report.
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.”
SOURCE MEG Energy Corp.
