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

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 bitumenreserves and resources 
effective as of December 31, 2012. Proved bitumenreserves 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 strategyat 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."

Investors Helen Kelly Director, Investor Relations 403-767-6206 
helen.kelly@megenergy.com

 Media Brad Bellows Director, External Communications 403-212-8705 
brad.bellows@megenergy.com

SOURCE: MEG Energy Corp.

To view this news release in HTML formatting, please use the following URL: 
http://www.newswire.ca/en/releases/archive/January2013/31/c9978.html

CO: MEG Energy Corp.
ST: Alberta
NI: OIL ERN CONF FIELD 

-0- Jan/31/2013 10:00 GMT


 
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