CALGARY, Feb. 2, 2012 /CNW/ - MEG Energy Corp. today reported fourth quarter 2011 operational and financial results. Highlights include:
- Record quarterly production volumes of 30,032 barrels of bitumen per day (bbls/d) following a successful plant turnaround in September;
- Strong cash operating netbacks of $54.64 per barrel, supported by high commodity prices, relatively narrow light-heavy crude differentials and low operating costs;
- Continuing progress on the 35,000 bbls/d design capacity Phase 2B, with the project remaining on budget and on schedule for 2013 completion;
- Year-end independent reserves evaluation reporting a 17% year-over-year increase in proved reserves to 708 million barrels and a 7% increase in proved plus probable reserves to more than 2 billion barrels.
MEG's net earnings for the fourth quarter of 2011 were $91.1 million ($0.46 per share, diluted) compared to $61.3 million ($0.31 per share, diluted) in the fourth quarter of 2010.
Operating earnings, which are adjusted for items that are not indicative of operating performance, increased in the fourth quarter of 2011 to $57.8 million ($0.29 per share) from $18.0 million ($0.09 per share) in the same period of 2010. Cash flow from operations for the fourth quarter of 2011 was $121.6 million ($0.61 per share) compared to cash flow of $64.7 million ($0.33 per share) in the fourth quarter of 2010. The increase in operating earnings and cash flow from operations was primarily due to higher production volumes and price realizations, as well as higher prices realized on electricity sales.
Production during the fourth quarter of 2011 averaged 30,032 bbls/d, MEG's highest quarterly volume to date. Comparative fourth quarter 2010 production averaged 27,744 bbls/d. Annual production for 2011 averaged 26,605 bbls/d, an increase of 25% over 2010 volumes of 21,257 bbls/d.
"Continuing strong performance through the fourth quarter lifted us to the high end of our production guidance of 25,000 to 27,000 barrels per day in 2011," said Bill McCaffrey, MEG President and Chief Executive Officer. "The great work by our reservoir and operations teams is also reflected in a low steam to oil ratio and low operating costs per barrel, which remain among the best in industry."
The steam to oil ratio ("SOR") in the fourth quarter of 2011 was 2.3, consistent with fourth quarter 2010 performance and remaining significantly better than the facility design rate of 2.8.
Operating costs for the three months ended December 2011 were $13.16 per barrel, compared to $13.89 per barrel for the same period in 2010. After including the contribution of revenue from power sales from MEG's cogeneration facilities, net operating costs decreased to $8.50 per barrel in the fourth quarter of 2011 from $11.01 per barrel in the fourth quarter of 2010. Low operating costs, coupled with relatively narrow light-heavy crude differentials and high benchmark prices, contributed to a fourth quarter cash operating netback of $54.64 per barrel, compared to $36.56 in the same period of 2010.
"Throughout 2011, we've continued to improve on four critical focus areas - increasing production, lowering our steam oil ratio, reducing per barrel costs and working to maximize the value of every barrel we produce" said McCaffrey. "An exceptional fourth quarter capped off a strong year and we plan to carry that momentum forward into 2012 as we continue to drive greater efficiencies in our current operations and lay the foundations for future growth."
Capital and growth strategy
Full year capital investment in 2011 was approximately $0.9 billion, which is in line with the estimate MEG provided in July 2011. The majority of the budget was invested in MEG's strategic plan to increase bitumen production capacity to 260,000 bbls/d by 2020.
The next major stage of the growth plan, Christina Lake Phase 2B, provides for an additional 35,000 bbls/d of design capacity. Approximately $710 million of the estimated $1.4 billion project cost has been invested to date and approximately 60% of the total budget is locked in. As at December 31, 2011, detailed engineering was 93% complete. All materials and project modules have been ordered, with delivery and on-site construction scheduled to continue through 2012 with completion targeted in 2013.
Subsequent to the end of the quarter, Alberta's Energy Resources Conservation Board issued an approval for MEG's multi-stage 150,000 bbls/d design capacity Christina Lake Phase 3 project. The remaining regulatory approvals for Phase 3 are expected in the first quarter of 2012.
In addition to ongoing construction of Phase 2B, MEG's $1.37 billion 2012 capital budget targets investments to begin development of future phases of the Christina Lake and Surmont projects, and investments in infrastructure to accommodate growth and add value to planned production by advancing MEG's market diversification strategy.
Underlying MEG's growth strategy is our large resource base. As additional resource delineation is undertaken as part of our long-term strategy, we expect to continue to reclassify contingent resources to the more certain proved and probable reserves categories.
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, 2011. Proved bitumen reserves were estimated to be 708 million barrels, an increase of 17% compared with December 31, 2010, while proved plus probable reserves increased by 7% to 2,060 million barrels. 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 $6.8 billion and $13.5 billion, respectively. GLJ's estimate of contingent resources (on a best estimate basis) increased slightly to approximately 3.8 billion barrels from 3.7 billion barrels. A summary of GLJ's report, along with important information regarding net present value calculations and the classification of reserves and contingent resources is included in MEG's Fourth Quarter 2011 Report to Shareholders.
OPERATIONAL AND FINANCIAL HIGHLIGHTS
The following table summarizes selected operational and financial information of the Corporation for the periods ended:
| Three months ended
| Year ended
|($/bbl unless specified)||2011||2010||2011||2010|
|Bitumen production - bbls/d||30,032||27,744||26,605||21,257|
|Steam to oil ratio||2.3||2.3||2.4||2.5|
|West Texas Intermediate (WTI) US$/bbl||94.06||85.18||95.12||79.53|
|Differential - WTI/Blend %||19.1%||25.8%||23.5%||23.0%|
|Net operating costs||8.50||11.01||10.96||16.13|
|Cash operating netback(1)||54.64||36.56||43.15||30.92|
|Net income - $000||91,118||61,271||63,837||49,558|
|Per share, diluted||0.46||0.31||0.32||0.27|
|Operating earnings - $000(2)||57,833||17,987||109,255||2,471|
|Per share, diluted(2)||0.29||0.09||0.55||0.01|
|Cash flow from operations - $000(2)||121,608||64,735||304,627||124,525|
|Per share, diluted(2)||0.61||0.33||1.54||0.68|
|Cash and short-term investments - $000||1,647,069||1,391,852||1,647,069||1,391,852|
|Long-term debt - $000||1,751,539||968,064||1,751,539||968,064|
|Capital cash investment - $000||268,814||143,164||928,921||483,372|
|Bitumen Reserves and Contingent Resources (Millions of barrels, before royalties)|
|Proved (1P) Reserves(3)||708||606|
|Proved Plus Probable (2P) Reserves(3)(4)||2,060||1,919|
|Best Estimate of Contingent Resources (2C)(5)(6)(7)||3,818||3,716|
|(1)||Cash operating netbacks are calculated by deducting the related royalties and diluent, 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 Operating Summary table within "Results of Operations" of the Fourth Quarter 2011 Report to Shareholders.|
|(2)||Operating earnings, 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 and investors with a measurement of the Corporation's ability to internally fund future growth expenditures. These "Non-IFRS Measurements" are reconciled to net income and net cash provided by operating activities in accordance with IFRS under the heading "Non-IFRS Measurements" in the Fourth Quarter 2011 Report to Shareholders.|
|(3)||"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".|
|(4)||"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".|
|(5)||"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.|
|(6)||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 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".|
|(7)||These volumes are the arithmetic sums of the Best Estimate Contingent resources for Christina Lake, Surmont and Growth Properties.|
A conference call will be held to review the financial results at 7:30 a.m. Mountain Time (9:30 a.m. Eastern Time) on Thursday, February 2, 2012. The U.S./Canada toll-free conference call number is 1 (888) 231-8191. The international/local conference call number is (647) 427-7450.
This news release may contain forward-looking information including but not limited to: estimates of reserves and resources; anticipated reductions in operating costs as a result of optimization of operations; and the anticipated capital requirements, timing for receipt of regulatory approvals, development plans, timing for completion, production capacities and performance of the future phases and expansions of the Christina Lake project. 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 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 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 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 "Risk Factors" and "Regulatory Matters" within MEG's annual information form dated February 24, 2011 (the "AIF") along with MEG's other public disclosure documents.
Statements in this news release relating to reserves and resources are deemed to be forward-looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the described reserves and resources, as the case may be, exist in the quantities predicted or estimated, and can be profitably produced in the future. This news release contains estimates of the Corporation's contingent resources. There is no certainty that it will be commercially viable to produce any portion of the Corporation's contingent resources. For further information regarding the classification and uncertainties related to MEG's estimated reserves and resources please see "Independent Reserve and Resource Evaluation" in the AIF. A copy of the AIF and of MEG's other public disclosure documents are available through the SEDAR website (www.sedar.com) or by contacting MEG's investor relations department.
Non-IFRS Financial Measures
Effective January 1, 2011, MEG adopted International Financial Reporting Standards ("IFRS"). This news release should be read in conjunction with the Corporation's audited Canadian GAAP financial statements and notes thereto for the year ended December 31, 2010 and the unaudited condensed financial statements and notes thereto for the period ended December 31, 2011. The unaudited condensed financial statements are included in the Fourth Quarter 2011 Report to Shareholders.
MEG Energy Corp. is focused on sustainable in situ oil sands development and production in the southern Athabasca 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."
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