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Pengrowth Executes on Sustainable Energy Strategy in 2012


Pengrowth Executes on Sustainable Energy Strategy in 2012

CALGARY, ALBERTA -- (Marketwire) -- 02/28/13 -- Pengrowth (TSX:PGF) (NYSE:PGH) had a strong year in 2012, highlighted by significant reserves growth, strategic acquisitions and dispositions and outstanding pilot performance at the Lindbergh thermal bitumen project. All of these milestones support Pengrowth's objective of becoming a sustainable, dividend paying, energy producer.

During 2012, Pengrowth increased proved and probable (2P) reserves by approximately 55 percent or 213 million barrels of oil equivalent (MMboe). The Company replaced 672 percent of 2012 production at an attractive Finding, Development and Acquisition (FD&A) cost, including changes in Future Development Capital (FDC) of $18.16 per boe.

The Lindbergh thermal bitumen project pilot results continue to outperform expectations. The pilot is currently producing more than 1,600 barrels per day (bbl/d) of bitumen with a steady, instantaneous steam oil ratio (ISOR) of 1.7. To date, the pilot has produced more than 425,000 barrels of bitumen from two well pairs. Based on the excellent pilot performance, the Pengrowth Board of Directors on January 10th, 2013 sanctioned and accelerated the first commercial phase of the Lindbergh project, which is expected to produce 12,500 bbl/d of bitumen when it becomes fully operational in early 2015, subject to regulatory approval.

"In 2012, Pengrowth made excellent progress on executing on its strategy of becoming a sustainable, dividend paying, energy producer, with the sanctioning, acceleration and expansion of the Lindbergh project and concurrent addition of 213 MMboe of 2P reserves at excellent FD&A costs," said Derek Evans, President and Chief Executive Officer of Pengrowth. "Economic reserves growth and net asset value (NAV) underpin the value of any oil and gas company. Pengrowth's NAV of $8.61 per share, based on GLJ Petroleum Consultant's (GLJ) 2P reserves value, is well above Pengrowth's current share price. We are committed to ensuring that the market understands Pengrowth's underlying value and strong growth prospects."

Highlights


 
--  Pengrowth remains committed to paying shareholders a dividend of 4 cents
    per share per month. 
--  The $315 million Weyburn disposition is scheduled to close in early
    March, 2013, strengthening the balance sheet to allow Pengrowth to
    accelerate its thermal strategy. 
--  Pengrowth's reserve additions in 2012 replaced 672 percent of 2012
    production, adding approximately 213 MMboe of additional 2P reserves at
    December 31, 2012 based on the evaluation by independent reserve
    evaluators GLJ. 2P reserves increased by 55 percent to total 512 MMboe,
    representing a 2P reserve life index of about 15 years. 
--  Annual FD&A costs of $18.16 per boe for 2P reserves including changes in
    FDC and $9.92 per boe for 2P reserves excluding FDC. 
--  At year-end 2012, Pengrowth's pre-tax net asset value stood at $8.61 per
    share based on GLJ's 2P reserves value, discounted at 10 percent. 
--  Continued outstanding Lindbergh thermal pilot results, with the two well
    pairs currently producing over 1,600 bbl/d of bitumen, at an ISOR of
    approximately 1.7. On January 10, 2013, the Pengrowth Board of Directors
    sanctioned and accelerated the development plan for Lindbergh, which
    envisions Lindbergh producing 12,500 bbl/d of bitumen by early 2015 and
    50,000 bbl/d by 2018, pending regulatory approval. 
--  Fourth quarter 2012 production averaged 94,039 barrels of oil equivalent
    per day (boe/d), representing a 23 percent increase from the fourth
    quarter of 2011 average production of 76,691 boe/d. 
--  2012 full-year average production volumes were 85,748 boe/d, a 16
    percent increase from the 2011 annual average production of 73,973
    boe/d. 
--  Successfully completed and integrated the NAL Energy acquisition, adding
    27,000 boe/d of production and significant Cardium oil drilling
    inventory. 

Financial Highlights


 
--  Fourth quarter 2012 funds flow from operations was $190 million ($0.37
    per share), up 35 percent from $141 million ($0.28 per share) in the
    third quarter 2012 and up 11 percent from $171 million ($0.50 per share)
    in the fourth quarter of 2011. 
--  Full year 2012 funds flow from operations of $539 million ($1.20 per
    share) was down 13 percent relative to 2011. Higher production levels in
    2012, offset by lower realized prices for oil and significantly lower
    realized natural gas prices, were the main reasons for the lower year
    over year funds flow. 
--  Issued U.S. $385 million equivalent of longer term notes, replacing
    shorter term bank debt inherited with the NAL Energy acquisition. 
--  Fourth quarter 2012 Adjusted Net Income increased to $24 million ($0.05
    per share) from a loss of $19 million in the third quarter, 2012.
    Compared to the fourth quarter of 2011, Adjusted Net Income increased by
    8 percent from $22 million. Full year 2012, Adjusted Net Loss was $90
    million ($0.20 per share). Decreased funds flow resulting from lower
    realized prices for oil and natural gas and increased impairment charges
    were the primary reasons for the reduction in Adjusted Net Income year
    over year. 
 
                  Summary of Financial & Operating Results                  
----------------------------------------------------------------------------
                                                                            
                                                                            
                         Three months                Twelve months          
                                ended                        ended          
(monetary amounts                                                           
 in millions,                                                               
 except per share                                                           
 and per boe                                                                
 amounts or as      Dec 31,   Dec 31,            Dec 31,   Dec 31,          
 otherwise stated)     2012      2011 % Change      2012      2011 % Change 
----------------------------------------------------------------------------
PRODUCTION                                                                  
Average daily                                                               
 production                                                                 
 (boe/d)             94,039    76,691       23    85,748    73,973       16 
----------------------------------------------------------------------------
CASH FLOW                                                                   
Funds flow from                                                             
 operations        $  189.7  $  171.1       11  $  538.8  $  620.0      (13)
Funds flow from                                                             
 operations per                                                             
 share             $   0.37  $   0.50      (26) $   1.20  $   1.87      (36)
                                                                            
Oil and gas sales                                                           
 (1)               $  431.5  $  389.2       11  $1,480.3  $1,453.7        2 
Oil and gas sales                                                           
 per boe           $  49.88  $  55.17      (10) $  47.17  $  53.84      (12)
                                                                            
Operating expense  $  121.2  $   99.7       22  $  458.6  $  382.0       20 
Operating expense                                                           
 per boe           $  14.01  $  14.13       (1) $  14.61  $  14.15        3 
                                                                            
Royalty expense    $   69.5  $   72.3       (4) $  277.5  $  277.9        - 
Royalty expense                                                             
 per boe           $   8.03  $  10.25      (22) $   8.84  $  10.29      (14)
Royalty expense as                                                          
 a percent of                                                               
 sales                 16.1%     18.6%              18.7%     19.1%         
                                                                            
Operating netback                                                           
 per boe           $  27.09  $  29.99      (10) $  22.93  $  28.45      (19)
                                                                            
Cash G&A expense   $   18.1  $   16.3       11  $   66.5  $   64.3        3 
Cash G&A expense                                                            
 per boe           $   2.09  $   2.31      (10) $   2.12  $   2.38      (11)
                                                                            
Capital                                                                     
 expenditures (2)  $   93.9  $  142.0      (34) $  467.4  $  608.5      (23)
Capital                                                                     
 expenditures per                                                           
 share             $   0.18  $   0.41      (56) $   1.05  $   1.83      (43)
                                                                            
Capital                                                                     
 expenditures                                                               
 including net                                                              
 cash acquisitions                                                          
 (2)               $  150.1  $  132.4       13  $  554.0  $  600.2       (8)
Capital                                                                     
 expenditures                                                               
 including net                                                              
 cash acquisitions                                                          
 per share         $   0.29  $   0.38      (24) $   1.24  $   1.81      (31)
                                                                            
Dividends paid     $   61.1  $   71.4      (14) $  289.1  $  277.5        4 
Dividends paid per                                                          
 share             $   0.12  $   0.21      (43) $   0.69  $   0.84      (18)
                                                                            
Number of shares                                                            
 outstanding at                                                             
 period end                                                                 
 (000's)            511,804   360,282       42   511,804   360,282       42 
Weighted average                                                            
 number of shares                                                           
 outstanding                                                                
 (000's)            509,960   345,163       48   447,232   332,182       35 
----------------------------------------------------------------------------
STATEMENT OF                                                                
 INCOME (LOSS)                                                              
Adjusted net                                                                
 income (loss)     $   24.1  $   22.3        8  $  (89.7) $  110.9     (181)
Net income (loss)  $   (1.1) $   (9.0)     (88) $   12.7  $   84.5      (85)
Net income (loss)                                                           
 per share         $      -  $  (0.03)       -  $   0.03  $   0.25      (88)
----------------------------------------------------------------------------
LONG TERM DEBT                                                              
Long term debt (3) $1,530.6  $1,007.7       52  $1,530.6  $1,007.7       52 
Convertible                                                                 
 debentures        $  237.1  $      -        -  $  237.1  $      -        - 
Total long term                                                             
 debt including                                                             
 convertible                                                                
 debentures        $1,767.7  $1,007.7       75  $1,767.7  $1,007.7       75 
----------------------------------------------------------------------------
CONTRIBUTION BASED                                                          
 ON OPERATING                                                               
 NETBACKS                                                                   
Light oil                66%       54%                69%       53%         
Heavy oil                10%       14%                12%       12%         
Natural gas                                                                 
 liquids                 13%       20%                15%       17%         
Natural gas              11%       12%                 4%       18%         
----------------------------------------------------------------------------
PROVED PLUS                                                                 
 PROBABLE RESERVES                                                          
Light oil (Mbbls)                                153,229   116,823       31 
Heavy oil (Mbbls)                                127,454    31,898      300 
Natural gas                                                                 
 liquids (Mbbls)                                  39,681    30,746       29 
Natural gas (Bcf)                                  1,150       906       27 
Total oil                                                                   
 equivalent (Mboe)                               511,960   330,511       55 
----------------------------------------------------------------------------
CAPITAL                                                                     
 PERFORMANCE                                                                
Finding &                                                                   
 Development Cost                                                           
 (F&D) (per boe)                                                            
 (4)                                            $  16.85  $  20.12      (16)
Finding,                                                                    
 Development &                                                              
 Acquisition Cost                                                           
 (FD&A) (per boe)                                                           
 (4)                                            $  18.16  $  20.04       (9)
Recycle ratio (5)                                    1.4       1.4        - 
----------------------------------------------------------------------------
                                                                            
(1) Includes the impact of realized commodity risk management contracts.    
(2) Prior periods restated to conform to presentation in the current period.
(3) Long-term debt includes the current and long-term portions.             
(4) Includes the changes in Future Development Capital (FDC) and based on   
    Proved plus Probable Reserves.                                          
(5) Recycle ratio is calculated as operating netback per boe divided by F&D 
    costs per boe based on Proved plus Probable reserves.                   

Production

Fourth quarter production averaged 94,039 boe/d, a 23 percent increase from 2011 fourth quarter average production of 76,691 boe/d. Full year 2012 average daily production of 85,748 boe/d represented a 16 percent increase from an average of 73,973 boe/d in 2011. Production increases associated with the NAL acquisition were partially offset by several unscheduled maintenance outages during the year. The Sable Offshore Energy Project (SOEP) continued to operate at 1,800 boe/d (net) below capability in the fourth quarter due to a pipeline shut down. Approximately 700 boe/d (net) of gas production was shut in throughout 2012 for economic reasons.

Operating expenses

Fourth quarter 2012 operating expenses were $121 million ($14.01 per boe) compared to $100 million ($14.13 per boe) in the same period of 2011. Full year operating expenses of approximately $459 million ($14.61 per boe) were 20 percent and 3 percent higher, respectively, compared to 2011. Additional operating expenses associated with the acquired NAL properties, coupled with extended maintenance activities were the primary reasons for the higher costs.

Development Capital

Pengrowth spent $93.9 million on development activities in the fourth quarter and participated in the drilling of 43 gross wells (17.8 net) within its key focus areas of Swan Hills and Greater Olds/ Garrington.

2012 development capital totaled $467.4 million, compared to guidance of $525 million, resulting in the drilling of 183 gross (93.3 net) wells. Approximately 79 percent of the 2012 development capital was spent on drilling, completion and facilities work, with the remainder directed to maintenance, land and corporate activities. During the year, Pengrowth reduced development capital as a result of lower natural gas prices and success with a number of tuck-in acquisitions, on which Pengrowth spent $113 million. The most significant tuck-in was in the Lochend area, which brought Pengrowth 530 boe/d and 32 additional Cardium drilling locations.

Operations

Swan Hills Trend

The Swan Hills Trend is a significant conventional oil resource, providing long term, low decline production and cash flow for the Company. This extensive carbonate oil reservoir provides Pengrowth with significant opportunities to put its expertise in horizontal drilling and multi-stage acid fracturing of carbonate reservoirs and significant control of infrastructure in the area to work on its operated interests in Judy Creek, Carson Creek, Deer Mountain, Virginia Hills and Sawn Lake.

During 2012, Pengrowth spent $170.7 million on development activities targeting light oil and liquids-rich opportunities and drilled a total of 24 operated wells (22.7 net), primarily targeting the tighter platform and R5 shoal. In addition, 12 partner-operated oil wells (2.5 net) were drilled targeting the House Mountain, Freeman and Sawn Lake plays.

Greater Olds/Garrington Area

Pengrowth holds a large, contiguous land base in the Greater Olds/Garrington area with over 500 gross sections of Cardium rights, extensive infrastructure and significant operatorship.

Activity in the Cardium continued in the fourth quarter with 2 operated (1.3 net) wells being drilled at Lochend. Both wells were completed and brought on production in January 2013. Non- operated Cardium drilling accounted for 7 (1.2 net) wells during the fourth quarter of 2012, all of which are expected to be on production in the first quarter of 2013.

During the fourth quarter, Pengrowth acquired additional assets in the Lochend area, adding approximately 530 boe/d of production with further optimization of this production expected in early 2013. This acquisition also added 32 net drilling locations. Pengrowth also increased its natural gas handling capacity at the Lochend battery with additional compression being added, which has significantly reduced incineration in the area.

For the full year 2012, Pengrowth spent $94.8 million on development activities in the Greater Olds/Garrington area, participating in the drilling of 41 wells (19.0 net).

Lindbergh

The Lindbergh property, located in the Cold Lake area of Alberta, is 100 percent owned and operated by Pengrowth. The Lindbergh thermal project targets the Lloydminster formation, where the bitumen has excellent flow characteristics and oil quality, which translates into higher netbacks. Based on positive pilot project results during 2012, the 12,500 bbl/d first commercial phase was sanctioned by the Board of Directors in January 2013 and, subject to regulatory approval, is expected to be constructed during 2013 and 2014.

The engineering phase of the 12,500 bbl/d first phase of Lindbergh is ongoing, with capital investment in critical path and long lead items being undertaken. Pending regulatory approval which is expected in the second quarter of 2013, field construction is slated to begin by mid-year with drilling activities to commence in the fourth quarter of 2013. Lindbergh is expected to provide Pengrowth with the potential to develop production of up to 50,000 bbl/d of bitumen over three phases of development. This is expected to be low cost, low decline, stable oil production, with a twenty-five year reserve life.

Pengrowth drilled 6 core holes at Lindbergh in the fourth quarter with results as anticipated. The wells were drilled in support of the commercial application currently being compiled for the second phase, which will increase the facility's capacity to 30,000 bbl/d. Pengrowth expects to submit this application by the end of 2013.

Oil and Gas Revenues

Fourth quarter oil and gas revenues of $432 million were 11 percent higher than the $389 million recorded in the fourth quarter of 2011. Full year 2012 oil and gas revenues increased by two percent to $1.48 billion compared to $1.45 billion for the full-year of 2011. Revenues from oil and liquids sales increased to 84 percent of total sales in 2012, up from 77 percent in 2011. Oil and liquids production accounted for 53 percent of production volumes in 2012.

Revenues were reduced by wider discounts for Canadian crude oil versus the West Texas Intermediate (WTI) benchmark price and significantly lower realized natural gas price. WTI light oil prices remained flat year-over-year, while Canadian light oil benchmark prices were 10 percent, or $9.07 per barrel lower in 2012, due to growing North American oil production and limited pipeline takeaway capacity. Pengrowth's realized light oil price, after commodity risk management, declined $5.91 per barrel to $83.58 per barrel. Weaker natural gas prices throughout 2012 also significantly reduced revenues. Realized natural gas prices of $2.49 per Mcf in 2012 were 39 percent lower than the $4.08 per Mcf realized price in 2011 including commodity risk management.

Funds Flow from Operations

Fourth quarter 2012 funds flow from operations was $190 million ($0.37 per share), up 35 percent from $141 million ($0.28 per share) in the third quarter 2012 and up 11 percent from $171 million ($0.50 per share) in the fourth quarter of 2011. Full year 2012 funds flow from operations of $539 million ($1.20 per share) was down 13 percent relative to $620 million ($1.87 per share) in 2011. Higher production levels in 2012, offset by lower realized prices for oil and significantly lower natural gas prices, were the main reasons for the lower year over year funds flows.

Financial Flexibility

Pengrowth remains committed to ensuring its financial sustainability in the face of a challenging commodity price environment. The Company has taken several measures intended to safeguard its dividend, maintain its financial and balance sheet strength and provide additional flexibility to ensure that it has the financial means and discipline to develop the Lindbergh thermal bitumen project. These include:


 
--  Selling non-core properties 
--  Expanding its commodity hedging program 
--  Managing interest costs through term debt markets 

During the fourth quarter of 2012, Pengrowth announced the ongoing rationalization of its asset base through the disposition of the non-operated Weyburn unit interest (2,500 boe/d net) in southeast Saskatchewan, for gross proceeds of $315 million, prior to closing adjustments. During the fourth quarter, Pengrowth issued U.S.$385 million equivalent of long term notes in five tranches with interest rates ranging from 3.45 percent to 4.74 percent and maturities ranging from seven to 12 years.

On January 11, 2013, Pengrowth announced plans to make additional dispositions targeting total proceeds of up to $700 million in 2013. The proceeds from these dispositions will be used to support the funding the first commercial phase of the Lindbergh thermal project.

In addition, Pengrowth has expanded its hedging program in order to manage its exposure to commodity price fluctuations. Pengrowth aims to hedge up to 65 percent of its production out two years, 30 percent in the third year and up to a maximum of 25 percent in the fourth and fifth years.

Increased hedging activity has resulted in Pengrowth having 65 percent of its oil production hedged for 2013 at Cdn$93.81 and for 2014 at Cdn$94.51 per barrel. Natural gas hedges account for 55 percent of 2013 production at Cdn$3.30 per Mcf. Additional details of Pengrowth's risk management contracts in place for 2013, 2014 and 2015 are outlined in the Management's Discussion and Analysis and Notes to the December 31, 2012 Audited Consolidated Financial Statements.

Pengrowth's total debt was approximately $1.8 billion as at December 31, 2012, comprising $160 million of bank debt, $1.4 billion of fixed rate term notes and $237 million of Convertible Debentures.

Including the proceeds from the Weyburn disposition with our expected funds flow from operations, Pengrowth expects that it will be able to fully fund its planned 2013 capital spending while maintaining the dividend, with no increase in total debt over 2012 debt levels. With the additional asset dispositions planned in 2013, Pengrowth expects to be able to pay down more of its existing debt and be in a position to fully fund the first phase of Lindbergh development of $300 million in 2013 and $290 million in 2014 with the remaining disposition proceeds.

Finding, Development and Acquisition Costs

During 2012, Pengrowth spent $461 million, net of information technology and office expenditures, on development and optimization activities, which added 21.0 MMboe of proved and 103.8 MMboe of 2P reserves including revisions. The largest 2P additions were at Lindbergh, where 2P reserves increased by 88.8 MMbbl due to further delineation drilling and superior pilot performance.

Pengrowth spent $1,654 million on acquisitions in 2012, net of proceeds from dispositions, adding 2P reserves of 109.4 MMboe.

Pengrowth's 2012 FD&A costs are summarized below. These are determined separately for exploration and development activities, and acquisition and disposition transactions, and with and without the change in future development costs. Future development costs reflect the amount of estimated capital that will be required to bring non-producing, undeveloped or probable reserves on stream. These forecasts of future development costs will change with time due to ongoing development activity, inflationary changes in capital costs and acquisition or disposition of assets. Pengrowth includes FD&A costs because it believes that acquisitions and dispositions can have a significant impact on its ongoing reserve replacement costs.


 
                                                               2010 - 2012  
                                2012             2011       Weighted Average
                          --------------------------------------------------
                                   Proved           Proved           Proved 
                                    plus             plus             plus  
                           Proved Probable Proved  Probable  Proved Probable
----------------------------------------------------------------------------
                                                                            
FD&A Costs Excluding                                                        
 Future Development                                                         
 Capital                                                                    
--------------------------                                                  
Exploration and                                                             
 Development Capital                                                        
 Expenditures - $MM          461.0   461.0   603.4    603.4  1,393.8 1,393.8
Exploration and                                                             
 Development Reserve                                                        
 Additions including                                                        
 Revisions - MMboe            21.0   103.8    41.0     39.3     82.6   170.2
----------------------------------------------------------------------------
Finding and Development                                                     
 Cost - $/boe                21.93    4.44   14.70    15.34    16.88    8.19
----------------------------------------------------------------------------
----------------------------------------------------------------------------
F&D Recycle Ratio, $/$         1.0     5.2     1.9      1.9      1.5     3.2
----------------------------------------------------------------------------
                                                                            
Net Acquisition Capital -                                                   
 $MM                       1,654.2 1,654.2    (8.3)    (8.3) 2,046.5 2,046.5
Net Acquisition Reserve                                                     
 Additions - MMboe            75.9   109.4    (0.2)    (0.3)    86.9   132.0
----------------------------------------------------------------------------
Net Acquisition Cost -                                                      
 $/boe                       21.81   15.12   52.06    32.85    23.54   15.51
----------------------------------------------------------------------------
                                                                            
Total Capital Expenditures                                                  
 including Net                                                              
 Acquisitions - $MM        2,115.2 2,115.2   595.1    595.1  3,440.3 3,440.3
Reserve Additions                                                           
 including Net                                                              
 Acquisitions - MMboe         96.9   213.2    40.9     39.1    169.5   302.2
----------------------------------------------------------------------------
Finding Development and                                                     
 Acquisition Cost - $/boe    21.83    9.92   14.56    15.23    20.30   11.38
----------------------------------------------------------------------------
                                                                            
FD&A Costs Including                                                        
 Future Development                                                         
 Capital                                                                    
--------------------------                                                  
Exploration and                                                             
 Development Capital                                                        
 Expenditures - $MM          461.0   461.0   603.4    603.4  1,393.8 1,393.8
Exploration and                                                             
 Development Change in FDC                                                  
 - $MM                       104.6 1,288.0   257.0    188.0    393.6 1,562.0
                          --------------------------------------------------
Exploration and                                                             
 Development Capital                                                        
 including Change in FDC -                                                  
 $MM                         565.6 1,748.9   860.4    791.4  1,787.4 2,955.8
Exploration and                                                             
 Development Reserve                                                        
 Additions including                                                        
 Revisions - MMboe            21.0   103.8    41.0     39.3     82.6   170.2
----------------------------------------------------------------------------
Finding and Development                                                     
 Cost - $/boe                26.91   16.85   20.96    20.12    21.65   17.36
----------------------------------------------------------------------------
----------------------------------------------------------------------------
F&D Recycle Ratio, $/$         0.9     1.4     1.4      1.4      1.2     1.5
----------------------------------------------------------------------------
                                                                            
Net Acquisition Capital -                                                   
 $MM                       1,654.2 1,654.2    (8.3)    (8.3) 2,046.5 2,046.5
Net Acquisition FDC - $MM    229.8   467.2     0.0      0.0    263.8   573.2
                          --------------------------------------------------
Net Acquisition Capital                                                     
 including FDC - $MM       1,884.0 2,121.4    (8.3)    (8.3) 2,310.3 2,619.7
Net Acquisition Reserve                                                     
 Additions - MMboe            75.9   109.4    (0.2)    (0.3)    86.9   132.0
----------------------------------------------------------------------------
Net Acquisition Cost -                                                      
 $/boe                       24.83   19.39   52.06    32.85    26.58   19.85
----------------------------------------------------------------------------
                                                                            
Total Capital Expenditures                                                  
 including Net                                                              
 Acquisitions - $MM        2,115.2 2,115.2   595.1    595.1  3,440.3 3,440.3
Total Change in FDC - $MM    334.4 1,755.2   257.0    188.0    657.4 2,135.2
                          --------------------------------------------------
Total Capital including                                                     
 Change in FDC - $MM       2,449.6 3,870.4   852.1    783.1  4,097.7 5,575.5
Reserve Additions                                                           
 including Net                                                              
 Acquisitions - MMboe         96.9   213.2    40.9     39.1    169.5   302.2
----------------------------------------------------------------------------
Finding Development and                                                     
 Acquisition Cost                                                           
 including FDC - $/boe       25.29   18.16   20.84    20.04    24.18   18.45
----------------------------------------------------------------------------
                                                                            
                                                                            
                                                                 2010 - 2012
                                      2012             2011 Weighted Average
                          --------------------------------------------------
Operating Netback ($/boe)                                                   
 (1)                                 22.93            28.45            25.94
(1) The operating netbacks are equal to sales revenue plus other income less
    royalties, operating expenses and transportation costs. Please see      
    Pengrowth's 2012 year-end Management Discussion & Analysis (MD&A) and   
    Annual Information Form (AIF) dated February 28, 2013 for further       
    information.                                                            
                                                                            
(2) The aggregate of the exploration and development costs incurred in the  
    most recent financial year and the change during that year in the       
    estimated future development costs generally will not reflect total F&D 
    costs related to reserves additions for that year.                      

Net Asset Value

The following table provides a calculation of Pengrowth's estimated net asset value at December 31, 2012, based on the estimated future net revenues associated with Pengrowth's proved plus probable reserves before income tax and discounted at 5 and 10 percent, as presented in the GLJ Report and including Pengrowth's internal assessment of undeveloped land values.


 
$Thousands, except per share amounts           5% Discount     10% Discount 
----------------------------------------------------------------------------
                                                                            
Value of Proved plus Probable Reserves (1)       8,703,000        6,088,000 
Undeveloped Lands (2)                              184,856          184,856 
Long Term Debt, convertible debentures and                                  
 working capital (3)                            (1,905,100)      (1,905,100)
Reclamation Funds (4)                               54,000           54,000 
Other Liabilities (ARO, commodity                                           
 contracts, private investment) (5)                (93,900)         (14,000)
----------------------------------------------------------------------------
Net Asset Value                                  6,942,856        4,407,756 
Shares Outstanding (000's)                         511,804          511,804 
NAV/share, $/share                                  $13.57            $8.61 
----------------------------------------------------------------------------
                                                                            
Notes:                                                                      
(1) GLJ total proved plus probable pre-tax discounted reserves value at     
    December 31, 2012.                                                      
(2) Internal land value estimate.                                           
(3) See December 31, 2012 financial statements and notes for additional     
    details.                                                                
(4) Prepaid reclamation costs for Sable Offshore Energy Project, Nova Scotia
    & Judy Creek, Alberta.                                                  
(5) Estimated value of commodity contracts and other liabilities.           

2013 Capital Program

The 2013 capital program includes $470 million for development activities, targeting light oil and liquids-rich natural gas production, mainly in the Greater Olds/Garrington area, Swan Hills and southeast Saskatchewan. In 2013, Pengrowth plans to participate in drilling 82 net wells excluding Lindbergh core hole drilling. An additional $300 million will be spent at Lindbergh in 2013, as Pengrowth positions itself for thermal oil production growth in 2014 and beyond.Total capital for the first commercial phase of Lindbergh is expected to be $590 million.

The 2013 capital program will focus on maximizing cash flow from existing assets while investing significant long-lead capital related to the first commercial phase of the low decline Lindbergh thermal bitumen project. The 2013 budget focuses on projects with the highest rates of return and maximum cash flow, with recycle ratios in excess of 2 times. It will be funded by operating cash flow and proceeds of $315 million from the non-core asset disposition of the Weyburn property.

2013 Funding Summary


 
                                                                ($ millions)
Forecast cash flow(1)(3)                                               $680 
Conventional capital                                                  ($470)
Lindbergh Capital                                                     ($300)
Dividends(2)                                                          ($250)
Anticipated DRIP proceeds                                               $50 
Disposition proceeds(3)                                                $315 
----------------------------------------------------------------------------
Net cash surplus                                                        $25 
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(1) Using mid-point of 2013 production guidance and assuming $90/bbl WTI,   
    $3.50/Mcf AECO and 9 percent and 23 percent discount for light oil and  
    heavy oil respectively.                                                 
(2) Assumes $0.04 per share per month dividend.                             
(3) Includes Weyburn disposition but excludes impacts of additional         
    dispositions.                                                           
                                                                            
2013 Full-Year Guidance Summary                                             
                                                                            
Average daily production volume (boe/d)              85,000 to 87,000       
Total capital expenditures ($millions)(1)                   770             
Royalties (% of sales)                                      17              
Net operating costs ($ per boe)                        14.00 - 14.50        
G & A expense (cash and non-cash) ($ per                                    
 boe)(2)                                                   3.30             
Transportation ($ per boe)                                 0.90             
----------------------------------------------------------------------------
(1) Includes $300 million at Lindbergh.                                     
(2) Includes $0.46/boe of non-cash G & A.                                   

All guidance numbers in this release are prior to the impact of any dispositions, other than the previously announced Weyburn disposition. Volumes from the Lindbergh pilot, which were excluded from Pengrowth's 2012 production volumes, have been included in the Company's 2013 full year guidance estimate and will be included in 2013 reported production.

Audited financial statements for the year ended December 31, 2012 and related Management's Discussion and Analysis can be viewed immediately on Pengrowth's website at www.pengrowth.com and have been filed on SEDAR at www.sedar.com and in Form 40-F on EDGAR at www.sec.gov/edgar.shtml.

Hard copies of the complete audited financial statements can also be requested free of charge by calling 1-888-744-1111, emailing investorrelations@pengrowth.com or requesting copies through www.pengrowth.com.

Reserves Information

GLJ conducted an independent evaluation of Pengrowth's reserves and contingent resources effective December 31, 2012. For further information on Pengrowth's December 31, 2012 reserves and contingent resources, please see the 2012 Year End Reserves news release dated February 28, 2013 and the Annual Information Form dated February 28, 2013, which are available at www.pengrowth.com, and have been filed on Form 40-F on EDGAR at www.sec.gov/edgar.shtml and on SEDAR at www.sedar.com.

Conference call:

Pengrowth will conduct a conference call with investors on Friday, March 1 at 6:30 AM Mountain Time (8:30 AM Eastern Time). Participants should call 1-877-240-9772 five minutes before the start of the call. A replay of the call will be made available until midnight Eastern Time on March 8, 2013 by calling 1-800-408-3053. The passcode is 6265274.

About Pengrowth:

Pengrowth Energy Corporation is a dividend-paying, intermediate Canadian producer of oil and natural gas, headquartered in Calgary, Alberta. Pengrowth's assets include the Swan Hills light oil, Cardium light oil and Lindbergh thermal bitumen projects. Pengrowth's shares trade on both the Toronto Stock Exchange under the symbol "PGF" and on the New York Stock Exchange under the symbol "PGH".

PENGROWTH ENERGY CORPORATION

Derek Evans, President and Chief Executive Officer

Advisory:

All amounts are stated in Canadian dollars unless otherwise specified.

Advisory Regarding Reserves and Production Information

All amounts are stated in Canadian dollars unless otherwise specified. All reserves, reserve life index, and production information herein is based upon Pengrowth's Company interest (Pengrowth's working interest share of reserves or production plus Pengrowth's royalty interest, being Pengrowth's interest in production and payment that is based on the gross production at the wellhead), before royalties and using GLJ Petroleum Consultants Ltd.'s January 1, 2013 forecast prices and costs.

Caution Regarding Engineering Terms:

When used herein, the term "boe" means barrels of oil equivalent on the basis of one boe being equal to one barrel of oil or NGLs or 6,000 cubic feet of natural gas (6 mcf: 1 bbl). Barrels of oil equivalent may be misleading, particularly if used in isolation. A conversion ratio of six mcf of natural gas to one boe is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All production figures stated are based on Company Interest before the deduction of royalties.

Initial production results and steam oil ratio

This press release references early production results (IP rates) and steam oil ratios for the Lindbergh pilot project. These results are not necessarily reflective of long-term production results, production profiles, steam oil ratios or ultimate performance of these wells or the project.

Caution Regarding Forward Looking Information:

This press release contains forward-looking statements within the meaning of securities laws, including the "safe harbour" provisions of the Canadian securities legislation and the United States Private Securities Litigation Reform Act of 1995. Forward-looking information is often, but not always, identified by the use of words such as "anticipate", "believe", "expect", "plan", "intend", "forecast", "target", "project", "guidance", "may", "will", "should", "could", "estimate", "predict" or similar words suggesting future outcomes or language suggesting an outlook. Forward-looking statements in this press release include, but are not limited to, statements with respect to Pengrowth's strategy, plans and objectives, maintaining dividend levels, future dividends, 2013 capital expenditures, the allocation thereof and the source of funding, anticipated Lindbergh production, the sources of funding for the Lindbergh project, the timing of the Linbergh project becoming operational and the receipt of all required regulatory approvals required in connection therewith and on the timing contemplated, the timing and plans relating to the second and third phase of Lindbergh, completion of the Weyburn disposition on the timing and for the consideration contemplated, IRR, net present value, costs and timing, drilling plans, drilling inventory, anticipated asset dispositions, reserve life, recycle ratios, the allocation of capital expenditures, production, production volumes, initial production rates, hedging plans, projected cash flow, funds flow, future borrowing, financing plans, future debt levels, DRIP proceeds, operating expenses, G&A, royalties and transportation costs, Pengrowth's production profile, liquids to gas ratio, reserves and the replacement thereof. Statements relating to "reserves" and "resources" are deemed to be forward-lookin g statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated and can profitably be produced in the future.

Forward-looking statements and information are based on current beliefs as well as assumptions made by and information currently available to Pengrowth concerning anticipated financial performance, business prospects, strategies and regulatory developments. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.

By their very nature, forward-looking statements involve inherent risks and uncertainties, both general and specific, and risks that predictions, forecasts, projections and other forward-looking statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in such forward-looking statements. These factors include, but are not limited to: changes in general economic, market and business conditions; the volatility of oil and gas prices; fluctuations in production and development costs and capital expenditures; the imprecision of reserve estimates and estimates of recoverable quantities of oil, natural gas and liquids; Pengrowth's ability to replace and expand oil and gas reserves; geological, technical, drilling and processing problems and other difficulties in producing reserves; environmental claims and liabilities; incorrect assessments of value when making acquisitions; increases in debt service charges; the loss of key personnel; the marketability of production; defaults by third party operators; unforeseen title defects; fluctuations in foreign currency and exchange rates; fluctuations in interest rates; inadequate insurance coverage; compliance with environmental laws and regulations; inability to receive regulatory and other third party approvals; actions by governmental or regulatory agencies, including changes in tax laws; Pengrowth's ability to access external sources of debt and equity capital; the impact of foreign and domestic government programs and the occurrence of unexpected events involved in the operation and development of oil and gas properties. Although the Corporation currently intends to maintain its monthly dividend, dividends can and may fluctuate in the future. Actual future cash dividends, if any, will be subject to the discretion of our Board of Directors and may vary depending on a variety of factors and conditions existing from time to time, including fluctuations in commodity prices, production levels, capital expenditure requirements, debt service requirements, operating costs, royalty burdens, foreign exchange rates and the satisfaction of the liquidity and solvency tests imposed by the ABCA for the declaration and payment of dividends.

Further information regarding these factors may be found under the heading "Business Risks" in our most recent management's discussion and analysis and under "Risk Factors" in our Annual Information Form dated February 28, 2013.

The foregoing list of factors that may affect future results is not exhaustive. When relying on our forward-looking statements to make decisions, investors and others should carefully consider the foregoing factors and other uncertainties and potential events. Furthermore, the forward-looking statements contained in this press release are made as of the date of this press release, and Pengrowth does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as required by applicable laws.

The forward-looking statements contained in this press release are expressly qualified by this cautionary statement.

Additional Information - Supplemental Non-IFRS Meas ures

In addition to providing measures prepared in accordance with International Financial Reporting Standards (IFRS), Pengrowth presents supplemental non-IFRS measures, Adjusted Net Income, operating netbacks and Funds Flow from Operations. These measures do not have any standardized meaning prescribed by IFRS and therefore are unlikely to be comparable to similar measures presented by other companies. These supplemental non-IFRS measures are provided to assist readers in determining Pengrowth's ability to generate cash from operations. Pengrowth believes these measures are useful in assessing operating performance and liquidity of Pengrowth's ongoing business on an overall basis.

These measures should be considered in addition to, and not as a substitute for, net income, funds flow from operating activities and other measures of financial performance and liquidity reported in accordance with IFRS. Further information with respect to these non-IFRS measures can be found in Pengrowth's most recent management's discussion and analysis

Note to US Readers

Current SEC reporting requirements permit oil and gas companies, in their filings with the SEC, to disclose probable and possible reserves, in addition to the required disclosure of proved reserves. Under current SEC requirements, net quantities of reserves are required to be disclosed, which requires disclosure on an after royalties basis and does not include reserves relating to the interests of others. Because we are permitted to prepare our reserves information in accordance with Canadian disclosure requirements, we have included contingent resources, disclosed reserves before the deduction of royalties and interests of others and determined and disclosed our reserves and the estimated future net cash therefrom using forecast prices and costs. See "Presentation of our Reserve Information" in our most recent Annual Information Form or Form 40-F for more information.

We report our production and reserve quantities in accordance with Canadian practices and specifically in accordance with NI 51-101. These practices are different from the practices used to report production and to estimate reserves in reports and other materials filed with the SEC by companies in the United States.

We incorporate additional information with respect to production and reserves which is either not generally included or prohibited under rules of the SEC and practices in the United States. We follow the Canadian practice of reporting gross production and reserve volumes; however, we also follow the United States practice of separately reporting these volumes on a net basis (after the deduction of royalties and similar payments). We also follow the Canadian practice of using forecast prices and costs when we estimate our reserves. The SEC permits, but does not require, the disclosure of reserves based on forecast prices and costs.

We include herein estimates of proved, 2P and possible reserves, as well as contingent resources. The SEC permits, but does not require the inclusion of estimates of probable and possible reserves in filings made with it by United States oil and gas companies. The SEC does not permit the inclusion of estimates of contingent resources in reports filed with it by United States companies. Contacts: Pengrowth Investor Relations (403) 233-0224 or Toll Free: 1-888-744-1111 investorrelations@pengrowth.com www.pengrowth.com

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