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MEG Energy records fifth consecutive year of production growth

 Solid fourth quarter operating results set the stage for a strong 2014  CALGARY, Feb. 6, 2014 /CNW/ - MEG Energy Corp. today reported fourth quarter  and full-year 2013 operational and financial results. Highlights include:            --  Strong performance from the recently commissioned Phase 2B             project and continued success of RISER driving record exit             production of 48,557  barrels per day (bpd), 13% above the top             end of guidance and setting a strong foundation for MEG's             near-term target of 80,000 bpd by 2015;         --  Establishing Canada's first well-head to unit-train rail             loading connection via pipeline, with MEG's first unit-train             shipment made in December 2013;         --  Annual net operating costs of $10 per barrel, maintaining MEG's             position as a low-cost producer; and         --  A 13% increase in proved reserves to 1.4 billion barrels and a             10% increase in proved plus probable reserves to 2.9 billion             barrels.  "The use of proven technologies was a key component to our performance in 2013  and will remain the central focus of our future plans. The success of MEG's  RISER initiative, coupled with the strong start-up performance of Christina  Lake Phase 2B in the fourth quarter, were the main contributors to our solid  production results in 2013," said Bill McCaffrey, MEG President and Chief  Executive Officer. "Exit rates were about 13 per cent above the high end of  our expectations, which provides a strong foundation for a very exciting year  in 2014 as we ramp-up toward our near-term target of 80,000 barrels per day by  2015."  Exit rate production for the month of December averaged 48,557 bpd. Annual  production for 2013 averaged 35,317 bpd, an increase of 23% over 2012 volumes  of 28,773 bpd, marking MEG's fifth consecutive year of annual production  gains. Production for the fourth quarter of 2013 increased to a record 42,251  bpd from fourth quarter 2012 production of 32,292 bpd.  Average non-energy operating costs for 2013, at $9.00 per barrel, were at the  low end of MEG's targeted range of $9 to $11 per barrel, an improvement of 7%  from 2012 averages. Net operating costs (including energy costs and revenue  from electricity sales) for 2013 averaged $10.01 per barrel, consistent with  2012 full-year results and maintaining MEG's low operating cost position. Net  operating costs for the fourth quarter of 2013 were $11.22 per barrel compared  to fourth quarter 2012 results of $8.95 per barrel. The difference in fourth  quarter net operating costs reflects the benefit of lower non-energy operating  costs, offset by higher natural gas energy costs and lower realized prices for  electricity sales.  Concurrent with the ramp-up of production in the fourth quarter, MEG  commissioned its proprietary 900,000 barrel Stonefell storage terminal and  completed its proprietary pipeline connection to the Canexus rail-loading  facility at Bruderheim, establishing the first direct well-head to rail  pipeline connection in the Canadian oil industry. The first unit-train of MEG  product was loaded in December with additional unit-trains loaded in January.  "The strategic advantage of having storage capability at the Stonefell  Terminal was demonstrated in the fourth quarter," said McCaffrey. "With the  Alberta oil industry subject to unscheduled pipeline apportionment, we were  able to continue producing at maximum rates while positioning ourselves to  take greater control of which markets our barrels are sold into, and the  timing for the sale of those barrels."  While fourth quarter 2013 production levels were up 31% from the same period  in 2012, sales volumes increased 10% due to approximately 6,300 bpd of  production being placed in storage, used as line-fill or capitalized in  association with the commissioning of Phase 2B.  Fourth quarter 2013 cash flow from operations was $22.6 million ($0.10 per  share, diluted) compared to cash flow from operations of $56.1 million ($0.27  per share, diluted) in the fourth quarter of 2012. Cash flow for the fourth  quarter of 2013 was impacted by production volumes that were not sold in the  quarter (as noted above), as well as wider light-heavy oil differentials and  an increase in diluent costs compared to the same period in 2012.  MEG recognized a net loss for the fourth quarter of 2013 of $148.2 million  compared to a net loss of $18.7 million for the fourth quarter of 2012. The  loss is primarily due to the unrealized foreign exchange loss on conversion of  the company's U.S. dollar denominated debt as a result of the strengthening of  the U.S. dollar against the Canadian dollar.  Capital and Growth Strategy  MEG's capital program in 2013 was approximately $2.1 billion. Investment was  primarily focused on completion of Christina Lake Phase 2B, continued  application of RISER at Christina Lake Phases 1 and 2, early work on RISER 2B,  and infrastructure to support MEG's future growth and marketing strategies.  "We've already put the capital in place to reach our target of 80,000 barrels  per day by 2015," said McCaffrey.  "The investment focus in 2014 is on our  next stage of growth through the RISER 2B initiative. The expansion of our  existing assets through this brownfield approach will significantly lower the  capital intensity of new production and accelerate our cash flows compared to  a typical greenfield expansion."  MEG ended the year with net debt of $2.9 billion, including $1.2 billion in  cash and cash equivalents. MEG's capital resources also include an undrawn  US$2.0 billion revolving credit facility.  Reserves Update  GLJ Petroleum Consultants Ltd. (GLJ), an independent reservoir engineering  firm, completed an evaluation of MEG's bitumen reserves and resources  effective as of December 31, 2013. Proved bitumen reserves increased by 13% to  an estimated 1.4 billion barrels from the previous year. Proved plus probable  reserves increased to 2.9 billion barrels from 2.6 billion barrels reflecting  higher expected recovery factors and further resource delineation. GLJ's  estimate of contingent resources (on a best estimate basis) was approximately  3.7 billion barrels, compared to 3.4 billion barrels a year earlier.  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 $13.5 billion and $21.0 billion, respectively. A summary of GLJ's  report, along with important information regarding net present value  calculations and the classification of reserves and contingent resources is  included in MEG's Fourth Quarter 2013 Report to Shareholders.  Operational and Financial Highlights                                                                                                    Three months ended December 31          Year ended December 31                             2013            2012            2013            2012     Bitumen     production -     bpd                   42,251          32,292          35,317          28,773     Bitumen     sales - bpd           35,990          32,722          33,715          28,845     Steam-oil     ratio (SOR)              2.9             2.4             2.6             2.4                                                                                      West Texas     Intermediate     (WTI)         US$/bbl            97.43           88.18           97.96           94.21     Differential     - Blend vs     WTI - %                40.6%           29.9%           32.7%           31.2%                                                                                      Bitumen     realization     - $/bbl                38.22           45.67           49.28           46.93                                                                                      Net     operating     costs(1)-     $/bbl                  11.22            8.95           10.01            9.98                                                                                      Non-energy     operating     costs -     $/bbl                   8.09            8.70            9.00            9.71                                                                                      Cash     operating     netback(2) -     $/bbl                  23.78           34.44           35.87           34.18                                                                                      Total cash     capital     investment     (3)- $000            389,232         494,916       2,188,353       1,598,514                                                                                      Net income     (loss) -     $000               (148,182)        (18,740)       (166,405)          52,569         Per     share,     diluted               (0.67)          (0.09)          (0.75)            0.26     Operating     earnings     (loss) -     $000(4)             (32,685)           (538)             386          21,242         Per     share,     diluted(4)            (0.15)          (0.00)            0.00            0.11     Cash flow     from     operations -     $000(4)               22,648          56,106         253,424         212,514         Per     share,     diluted(4)              0.10            0.27            1.13            1.06                                                                                      Cash, cash     equivalents     and     short-term     investments     - $000             1,179,072       2,007,841       1,179,072       2,007,841     Long-term     debt - $000        4,004,575       2,488,609       4,004,575       2,488,609                                                                                      Bitumen Reserves and Contingent Resources (millions of barrels, before     royalties)       Bitumen Reserves (millions of barrels,     before royalties)                                                                  Proved (1P) Reserves(5)                              1,446           1,284       Probable Reserves(6)                                 1,451           1,360       Proved Plus Probable (2P) Reserves(5)(6)             2,897           2,644                                                                                        Bitumen Contingent Resources (millions of barrels, before royalties)       Best Estimate Contingent Resources (2C)(7)     (8)(9)                                                 3,653           3,420     (1)  Net operating costs include energy and non-energy operating costs,          reduced by power sales.     (2)  Cash operating netbacks are calculated by deducting the related          diluent, transportation, field operating costs and royalties from          proprietary sales volumes and power revenues, on a per barrel          basis.     (3)  Includes capitalized interest of $22.9 million and $76.5 million          for the three months and year ended December 31, 2013 respectively          ($10.4 million and $30.6 million for the three months and year          ended December 31, 2012).     (4)  Please refer to Non-IFRS Financial Measures below.     (5)  "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".     (6)  "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".     (7)  "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.     (8)  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".     (9)  These volumes are the arithmetic sums of the Best Estimate          Contingent Resources for Christina Lake, Surmont and the Growth          Properties.  A full version of MEG's Fourth Quarter 2013 Report to Shareholders, including  the unaudited financial statements, is available at  www.megenergy.com/investors and at www.sedar.com.  A conference call will be held to review MEG's fourth quarter results at 7:30  a.m. Mountain Time (9:30 a.m. Eastern Time) on Thursday, February 6, 2014. The  U.S./Canada toll-free conference call number is 1 888-231-8191. The  international/local conference call number is 647-427-7450.  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, SORs, pricing differentials, reliability, profitability and  capital investments; estimates of reserves and resources; the anticipated  reductions in operating costs as a result of optimization and scalability of  certain operations; the anticipated capital requirements, timing for receipt  of regulatory approvals, development plans, timing for completion,  commissioning and start-up, capacities and performance of the Access Pipeline  expansion, the RISER initiative, the Stonefell Terminal, third party barging  and rail facilities, the future phases and expansions of the Christina Lake  project, the Surmont project and potential projects on the Growth Properties;  and the 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 (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 February 27, 2013 (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, 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 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  (loss) 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 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 Fourth Quarter 2013 Report to  Shareholders.  MEG Energy Corp. is focused on sustainable in situoil 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.  Investors John Rogers Vice President, Investor Relations and External  Communications 403-770-5335 john.rogers@megenergy.com  Media Brad Bellows Director, External Communications 403-212-8705  brad.bellows@megenergy.com  To view this news release in HTML formatting, please use the following URL:  http://www.newswire.ca/en/releases/archive/February2014/06/c7944.html  CO: MEG Energy Corp. ST: Alberta NI: OIL ERN CONF