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 
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CO: MEG Energy Corp.
ST: Alberta
NI: OIL ERN CONF  
-0- Feb/06/2014 10:00 GMT
 
 
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