MEG Energy reports record quarterly, annual and exit-rate production volumes

Production and marketing strategies to reach major milestones in 2013

CALGARY, ALBERTA (January 31, 2013) – 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 U.S. 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 December 31 Year ended December 31
($/bbl unless specified) 2012 2011 2012 2011
Bitumen production – bpd 32,292 30,032 28,773 26,605
Steam to oil ratio 2.4 2.3 2.4 2.4
West Texas Intermediate (WTI) US$/bbl 88.18 94.06 94.21 95.12
Differential – WTI/Blend % 29.9% 18.2% 31.2% 23.5%
Bitumen realization 45.67 67.99 46.93 58.74
Net operating costs (1) 8.95 8.50 9.98 10.96
Cash operating netback(2) 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, diluted (0.09) 0.46 0.26 0.32
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(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 and at

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 ( 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."