Pengrowth Announces 55 Percent Increase in 2012 Year-End Proved Plus Probable Reserves and Replacement of 672 Percent of 2012

Pengrowth Announces 55 Percent Increase in 2012 Year-End Proved Plus Probable 
Reserves and Replacement of 672 Percent of 2012 Production 
CALGARY, ALBERTA -- (Marketwire) -- 02/28/13 -- Pengrowth Energy
Corporation (TSX:PGF) (NYSE:PGH) is pleased to announce strong 2012
year-end reserve additions. 

--  Proved plus probable (2P) reserves increased by 55 percent to 512.0
    million barrels of oil equivalent (MMboe) at December 31, 2012 from
    330.5 MMboe at year-end 2011. 
--  Pengrowth replaced 672 percent of 2012 production, adding 213.2 MMboe of
    2P reserves in 2012 at an all-in annual Finding, Development and
    Acquisition (FD&A) cost of $18.16 per boe including changes in Future
    Development Capital (FDC) for 2P reserves. The 2012 FD&A costs,
    excluding changes to FDC were $9.92 per boe for 2P reserves. 
--  All-in Finding and Development (F&D) costs were $16.85 per boe for 2P
    reserves including changes in FDC.
--  Pengrowth's three year average all-in FD&A and F&D costs for 2P reserves
    were $18.45 per boe and $17.36 per boe, respectively, including FDC
    ($11.38 per boe and $8.19 per boe, respectively, excluding FDC).
--  2012 crude oil and natural gas liquids (NGL) reserves increased by 29
    percent and 79 percent on a proved (1P) and 2P basis, respectively. This
    significant increase in liquids reserves is a direct result of reserves
    acquired through the acquisition of NAL Energy Corporation (NAL) as well
    as focusing capital on oil and liquids-rich projects, particularly the
    Lindbergh thermal project. 
--  At Lindbergh, reserves were increased significantly with 89 MMbbl of
    reserve additions due to delineation drilling and positive pilot
    results. At year-end 2012, 2P reserves stood at 95 MMbbl while 1P
    reserves were 13 MMbbl. The best estimate incremental contingent
    resources were 218 MMbbl. 
--  2P reserve life index (RLI) increased to 14.7 years at year-end 2012, a
    23 percent increase from the year-end 2011 figure of 12.0 years. 

Pengrowth's 2P reserves at year-end 2012 were 512.0 MMboe based on an
independent engineering evaluation conducted by GLJ Petroleum
Consultants Ltd. (GLJ) effective December 31, 2012 and prepared in
accordance with National Instrument 51-101 (NI 51-101) and the
Canadian Oil and Gas Evaluation Handbook (COGEH). This represents a
55 percent increase in 2P reserves since December 31, 2011 resulting
from a combination of acquisitions, drilling activity and increased
reserve bookings at Lindbergh. Pengrowth replaced 672 percent of 2012
annual production through the addition of a total of 213.2 MMboe of
2P reserves offset by 31.7 MMboe of production, including 0.3 MMboe
from the Lindbergh pilot. 
Pengrowth's total proved reserves of 300.1 MMboe account for 59
percent of total 2P reserves. Proved producing reserves of 237.7
MMboe represent approximately 79 percent of the total proved
Using a 6:1 boe conversion rate for natural gas, approximately 30
percent of 2P reserves are light/medium crude oil, 25 percent are
heavy oil and bitumen, 8 percent are NGL and 37 percent are natural
Using a 10 percent present value discount factor and GLJ's January 1,
2013 pricing forecast, proved producing reserves and total proved
reserves account for 61 and 70 percent respectively, of the 2P
reserves before tax present value of $6.1 billion. 
Company Interest Reserves Summary - December 31, 2012  
(GLJ January 1, 2013 forecast prices and costs) 

                                   Light &                          Natural 
                                    Medium                              Gas 
                                 Crude Oil  Heavy Oil    Bitumen    Liquids 
                                     (Mbbl)     (Mbbl)     (Mbbl)     (Mbbl)
Proved Producing                    85,484     15,486      1,653     25,749 
Proved Developed Non-Producing       2,333         78          0        845 
Proved Undeveloped                  20,025      6,122     11,136      1,831 
Total Proved                       107,841     21,687     12,789     28,425 
Total Probable                      45,388     10,975     82,003     11,256 
Total Proved Plus Probable (2P)    153,229     32,662     94,792     39,681 
                                                   Total Oil Percent of 2P  
                                      Natural     Equivalent           Oil  
                                     Gas (Bcf)         (Mboe)Equivalent (%) 
Proved Producing                        655.9        237,685            46% 
Proved Developed Non-Producing           21.8          6,883             1% 
Proved Undeveloped                       98.3         55,510            11% 
Total Proved                            776.0        300,078            59% 
Total Probable                          373.6        211,882            41% 
Total Proved Plus Probable (2P)       1,149.6        511,960           100% 

2012 Operational and Property Review 
Capital expenditures in 2012 were $467 million, before property
acquisitions and dispositions. Pengrowth participated in drilling 183
gross (93.3 net) wells in 2012. The 2012 capital program yielded
103.8 MMboe of 2P reserve additions, including revisions,
representing a 327 percent replacement of 2012 production. As a
result of the successful pilot results and ongoing development
activities, the Lindbergh thermal project contributed the largest
increase where 88.8 MMboe of 2P reserves were added bringing the
total 2P Lindbergh reserves to 94.8 MMboe. 
In addition to the NAL acquisition, Pengrowth spent $87 million on
property acquisitions, net of disposition proceeds. In aggregate,
this added 110.8 MMboe of 2P reserves offset by the divesture of
certain non- core properties with attributed 2P reserves of 1.4
Additional 2012 development activities and 2013 planned activities
for each core area are outlined below: 
Swan Hills Area 
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 to
work on its operated interests in Judy Creek, Carson Creek, House
Mountain, Deer Mountain and Virginia Hills. 
In 2012, Pengrowth spent $170.7 million on light oil and liquids-rich
gas plays in the Swan Hills area, participating in the drilling of 36
gross (25.2 net) wells. In addition to ongoing miscible flood
development and waterflood optimization, 2012 activity was primarily
focused on the development of the tighter platform and R5 shoal zones
at Judy Creek, Deer Mountain, Virginia Hills and Carson Creek.
Further partner-operated development targeted the 
House Mountain,
Freeman and Sawn Lake areas. 
In 2013, Pengrowth plans to invest $132 million on light oil and
liquids-rich gas plays in the Swan Hills trend. The 2013 program
includes approximately 15 net operated and non-operated drills, as
well as significant optimization activities in Judy Creek, Virginia
Hills, Sawn Lake, Deer Mountain and House Mountain. 
At Judy Creek, Pengrowth will continue to exploit numerous
development opportunities in the Beaverhill Lake A and B pools with
new drills, re-entries, recompletions and workovers. The remainder of
Pengrowth's activity will focus on expanding its footprint within the
Swan Hills trend by developing opportunities identified at Deer and
House mountains, Virginia Hills and Sawn Lake. Pengrowth also holds a
100% working interest in 47 sections of land on an undeveloped
platform margin play in the Devil area with significant upside
potential, which the Company intends to exploit in 2013. 
The Olds/Garrington area is located in south-central Alberta and is
comprised of stacked reservoirs offering multi-zone potential
targeting light oil and liquids-rich natural gas development.
Opportunities in the area are centered on the exploitation of the
Lochend and Garrington Cardium oil and Harmattan Elkton and Mannville
liquids-rich natural gas plays. These plays provide Pengrowth with a
complementary set of opportunities that will support continued
capital development in this area for several years. In 2012,
Pengrowth spent $95 million in the Olds/Garrington area on activities
targeting the Elkton, Mannville and Cardium plays, drilling 35 gross
(17.8 net) wells during the year. 
Capital expenditures in this area in 2013 are expected to be
approximately $200 million, primarily targeting Cardium light oil
($163 million/40 net wells) in the Lochend and Garrington areas. 
At Lochend, Pengrowth recently acquired additional high working
interest Cardium lands which are included in its 2013 development
plans. These are prolific, light oil wells with approximate netbacks
of $64/bbl and recycle ratios in excess of 3.0 times. 
Additional capital has been allocated to the Elkton and Mannville
liquids-rich natural gas plays, which are characterized by their high
liquids content (approximately 50 to 90 bbls/ MMcf) providing strong
economic returns and cash flows. 
Pengrowth currently has six rigs drilling in the Olds/Garrington area
and anticipates drilling over 50 net wells in 2013. 
The Lindbergh thermal project is a key component of Pengrowth's
growth strategy, with the potential to grow oil production by up to
50,000 barrels per day (bbl/d) of bitumen. The Lindbergh property,
encompassing 42.5 sections of land in the Cold Lake area of Alberta,
is 100 percent owned and operated by Pengrowth. This 11 degrees API
oil has favorable viscosity characteristics and is in a clean,
continuous, high permeability reservoir. Lindbergh is expected to
provide Pengrowth with the potential to develop a significant
commercial project of low cost, low decline, stable oil production,
with a 25 year reserve life. 
Pengrowth began steam injection into the Lindbergh pilot project in
February 2012. Pilot production rates and instantaneous steam oil
ratio (ISOR) outperformed expectations during the year. The pilot,
which consists of two well pairs, has been in operation for over 10
months and is currently producing in excess of 1,600 bbl/d of
bitumen, with a consistent ISOR of 1.7. To date, the Pilot has
produced more than 425,000 bbls of bitumen. 
The excellent pilot results and associated reserve potential have
provided Pengrowth with the confidence needed to accelerate and
expand the first phase of commercial development. As of year-end
2012, GLJ estimated 95 MMbbl of 2P reserves and 218 MMbbl of
additional best estimate contingent resources for Lindbergh. On
January 10, 2013, Pengrowth's Board of Directors approved the first
phase of Lindbergh commercial development, which is expected to reach
12,500 bbl/d of bitumen by early 2015. Two additional expansion
phases are expected to increase total Lindbergh production to 50,000
bbl/d of bitumen by 2018. 
Pengrowth plans to spend $300 million at Lindbergh in 2013, inclusive
of $55 million announced in December 2012. This capital will be spent
on long lead items, starting construction of the central processing
facility in the second quarter and the drilling of 8 of 23 well pairs
which is expected to commence in the fourth quarter. 
Regulatory, environmental, landowner and First Nations discussions
surrounding Lindbergh are on track. Pengrowth anticipates regulatory
and environmental approvals for Phase 1 to be granted in Q2 2013. 
Reserves Reconciliation 
Total 2P reserve additions in 2012 were 213.2 MMboe, replacing
production by 672 percent and growing reserves at year-end by 55
percent compared to 2011. 
Reserve additions of 103.8 MMboe, including revisions, resulted from
drilling and improved recovery projects. The most significant of
these additions were reserves attributed to the Lindbergh thermal
project, where 2P reserves increased by 88.8 MMboe in 2012 over
year-end 2011 numbers. 
Acquisitions contributed to an additional 110.8 MMboe of 2P reserves
being added in 2012, offset by minor dispositions of 1.4 MMboe. 
Company Interest Reserves Reconciliation 2012     
(GLJ January 1, 2013 forecast prices and costs)    

                   Light &                      Natural                     
                    Medium                          Gas  Natural  Total Oil 
                     Crude  Heavy Oil  Bitumen  Liquids      Gas Equivalent 
                 Oil (Mbbl)     (Mbbl)   (Mbbl)   (Mbbl)    (Bcf)     (Mboe)
Total Proved                                                                
December 31, 2011   85,455     19,676    4,436   22,512    617.0    234,910 
 Revisions           1,686        733        1      770     27.5      7,735 
Drilling             2,914      3,172    8,678      705     15.3     18,030 
Improved Recovery    1,009        267        0      148      0.2      1,461 
Acquisitions        28,058        515        0    8,801    236.5     76,826 
Dispositions           (93)      (164)       0      (67)    (3.8)      (963)
Economic Factors      (938)      (129)       0     (516)   (27.8)    (6,211)
Production         (10,250)    (2,384)    (326)  (3,927)   (88.9)   (31,710)
December 31, 2012  107,841     21,687   12,789   28,425    776.0    300,079 
Total Proved Plus                                                           
December 31, 2011  116,823     25,550    6,348   30,746    906.3    330,511 
 Revisions           1,086        608        1     (423)    14.3      3,615 
Drilling             4,762      8,068   88,769
    1,067     16.2    105,356 
Improved Recovery    1,406        248        0       34      0.2      1,719 
Acquisitions        40,337        958        0   12,747    340.4    110,814 
Dispositions          (145)      (218)       0     (103)    (5.8)    (1,426)
Economic Factors      (790)      (168)       0     (459)   (33.0)    (6,919)
Production (1)     (10,250)    (2,384)    (326)  (3,927)   (88.9)   (31,710)
December 31, 2012  153,229     32,662   94,792   39,681  1,149.6    511,960 
(1) For reserves reporting purposes, 2012 annual production includes        
    production from the Lindbergh pilot, which is not included in the       
    production figures in our financial disclosure.                         

Before Income Tax Net Present Value Summary as at December 31, 2012  
(GLJ January 1, 2013 forecasted prices and costs) 

                                            Discounted at                   
                                                                 Percent of 
($ 000, except                                                   Discounted 
 percentages)          Undiscounted      5%    10%    15%    20%      at 10%
Proved Producing              6,143  4,610  3,704  3,110  2,693          61%
Proved Developed Non-                                                       
 Producing                      208    125     86     64     50           1%
Proved Undeveloped            1,521    793    465    284    172           8%
Total Proved                  7,872  5,528  4,255  3,458  2,916          70%
Total Probable                6,059  3,175  1,834  1,127    717          30%
Total Proved Plus                                                           
 Probable (2P)               13,931  8,703  6,088  4,586  3,632         100%

Select streams of GLJ's January 1, 2013 forecast prices and inflation
rates for costs are shown below: 

                 WTI Crude   Edm Light   WCS Crude  Natural Gas   Inflation 
                       Oil   Crude Oil         Oil      at AECO        Rate 
Year              ($US/bbl)  ($Cdn/bbl)  ($Cdn/bbl) ($Cdn/MMBtu)    (%/year)
2012 (Actual)        94.10       86.86       73.29         2.45           - 
2013                 90.00       85.00       70.13         3.38         2.0 
2014                 92.50       91.50       76.15         3.83         2.0 
2015                 95.00       94.00       78.22         4.28         2.0 
2016                 97.50       96.50       80.29         4.72         2.0 
2017                 97.50       96.50       80.29         4.95         2.0 
2018                 97.50       96.50       80.29         5.22         2.0 
2019                 98.54       97.54       81.16         5.32         2.0 
2020                100.51       99.51       82.79         5.43         2.0 
2021                102.52      101.52       84.46         5.54         2.0 
2022                104.57      103.57       86.16         5.64         2.0 
Thereafter        +2.0%/yr    +2.0%/yr    +2.0%/yr     +2.0%/yr         2.0 

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 MMboe 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 (FDC). FDC reflects 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                                                         
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                                                               
 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                                                         
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                                                               
 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       
(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.                      

Total Future Net Revenue (Undiscounted)  
(GLJ January 1, 2013 forecast pricing and costs) 

                                 Revenue   Royalties   Operating Development
($millions)                                                Costs       Costs
Proved Producing                  15,098       2,646       5,694         265
Proved Developed Non-                                                       
 Producing                           427         103          89          23
Proved Undeveloped                 4,425         724       1,249         906
Total Proved
                      19,950       3,473       7,032       1,194
Total Probable                    15,303       3,032       4,312       1,828
Total Proved Plus Probable        35,253       6,505      11,344       3,022
                                             Revenue                 Revenue
                             Abandonment      Before      Income       After
($millions)                    Costs (1)  Income Tax     Tax (2)  Income Tax
Proved Producing                     350       6,143         351       5,792
Proved Developed Non-                                                       
 Producing                             4         208          55         153
Proved Undeveloped                    25       1,521         418       1,103
Total Proved                         379       7,872         825       7,047
Total Probable                        72       6,059       1,588       4,471
Total Proved Plus Probable           451      13,931       2,412      11,519

(1) Includes GLJ's estimate of well abandonment costs and abandonment costs 
    for Sable Island facilities and subsea pipelines, but does not include  
    abandonment costs for other facilities or any surface reclamation costs.
    Please see our AIF for further information.                             
(2) Income tax values were calculated by Pengrowth using GLJ's before tax   
    cash flow, current corporate tax rates, existing tax pools and additions
    to the tax pools through capital expenditures as forecast by GLJ. Please
    see our AIF for further information.                                    

Reserve Life Index 
Pengrowth's proved RLI increased to 9.2 years from 9.0 years in 2011.
The RLI for proved plus probable reserves increased to 14.7 years at
year-end 2012, a 23 percent increase from the year-end 2011 figure of
12.0 years. 

Reserve Life Index (years)          2012        2011        2010        2009
Proved Producing                     7.6         7.6         7.2         7.3
Total Proved                         9.2         9.0         8.2         8.3
Total Proved plus Probable          14.7        12.0        11.1        10.6

RLI refers to the number of years determined by dividing Company
Interest reserves of a property by the next year's forecast Company
Interest production for the corresponding reserve category from such
property. The reserves and next year's forecast production for such
property come from the GLJ Report. 
Tax Pools 
Pengrowth's tax pools totaled approximately $4.5 billion as at
December 31, 2012. The table below provides an estimate of tax pools
by category as at December 31, 2012. These estimates are based upon
forecasts prepared internally and have not been verified by any
provincial or federal taxing authority. Pengrowth does not anticipate
being subject to any cash income taxes prior to 2017. 

Tax Pools                                                       ($ millions)
COGPE                                                                  1,564
CDE                                                                      891
UCC                                                                      851
CEE                                                                      161
Other (Injectants, etc.)                                               1,005
Total Tax Pools                                                        4,472

Reserves and Contingent Resources Classification 
Reserves and contingent resources included herein are stated on a
company-interest basis (working interest before deduction of
royalties and including any company royalty interests) unless noted
otherwise. All reserves information has been prepared in accordance
with NI 51-101 Standards of Disclosure for Oil and Gas Activities and
COGEH. In addition to the information disclosed in this news release,
more detailed information is included in Pengrowth's Annual
Information Form (AIF). 
The following table summarizes GLJ's estimate of reserves and
economic contingent resources, as of year-end 2012, for the Lindbergh
oil sands property and Groundbirch natural gas property. 

                      Reserves (MMboe)         Contingent Resources (MMboe) 
                                     Proved +                               
                          Proved + Probable +        Low      Best      High
Field             Proved  Probable   Possible   Estimate  Estimate  Estimate
Lindbergh             13        95        155        194       218       328
Groundbirch           11        28         33         26        46        83

The contingencies which prevent the contingent resources from being
classified as reserves at Lindbergh include the need for additional
evaluation well drilling within the area, firm development plans,
high quality project design and cost estimates and commitment by
Pengrowth for future development phases, and submission of regulatory
application to expand the currently proposed development area. 
The primary contingency which prevents the contingent resources at
Groundbirch to be classified as reserves is the early evaluation and
delineation stage of the tight gas resource. Additional drilling,
completion and testing data is required before Pengrowth can commit
to further development. 
Pengrowth's AIF dated February 28, 2013 can be accessed immediately
on Pengrowth's website at, and has been filed on
SEDAR at and as a Form 40-F on EDGAR at 
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 Regarding Reserves, Contingent Resources and Production
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 deduction of royalty obligations and using GLJ's
January 1, 2013 forecast prices and costs as disclosed herein.
Numbers presented may not add due to rounding. 
The estimated value of reserves disclosed in this press release do
not represent fair market value of the reserves. 
The estimates of reserves and future net revenues for individual
properties may not reflect the same confidence level as estimates of
reserves and future net reven
ue for all properties, due to effects of
aggregation. 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
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. The contingencies may
include factors such as economics, legal, environmental, political
and regulatory matters or lack of markets. Contingent Resources are
further classified in accordance with the level of certainty
associated with the estimates. Contingent Reserves do not constitute
and should not be confused with reserves. There is no certainty that
it will be commercially viable to produce any portion on the
Contingent Resources. The estimates of Contingent Resources
associated with Pengrowth's Lindbergh Oil Sands property and
Groundbirch gas property included herein have been evaluated by GLJ,
Pengrowth's independent qualified reserves evaluator, in accordance
with COGEH and NI 51-101. A best estimate is the estimate of the
quantity of resource that will be recovered from the accumulation,
which under probabilistic methodology reflects a 50 percent
confidence level. A low estimate is the estimate of the quantity of
resource that will be recovered from the accumulation, which under
probabilistic methodology reflects a 90 percent confidence level. A
high estimate is the estimate of the quantity of resource that will
be recovered from the accumulation, which under probabilistic
methodology reflects a 10 percent confidence level. The Contingent
Resources as disclosed herein are considered economic based on
forecast prices and costs as at December 31, 2012. Additional
information relating to the Contingent Resources estimate for
Pengrowth's Lindbergh Oil Sands property and Groundbirch gas
property, including specific contingencies and significant positive
and negative factors associated with the estimate, can be found in
Pengrowth's AIF dated February 28, 2013, which can be accessed
immediately on Pengrowth's website at and has been
filed on SEDAR at and as Form 40-F on EDGAR at 
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 2013 capital expenditures and the allocation thereof,
anticipated Lindbergh production, IRR, net present value, costs and
timing, drilling plans, liquids content of production, recycle
ratios, production, production volumes, operating costs, royalties,
future taxes and tax pools, future development 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 -looking 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
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; 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. 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 Pengrowth's AIF. 
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. 
Non-GAAP Financial Measures 
This news release refers to certain financial measures that are not
determined in accordance with International Financial Reporting
Standards (IFRS). These measures do not have standardized meanings
and may not be comparable to similar measures presented by other oil
and gas companies. Measures such as operating netbacks do not have
standardized meanings prescribed by Generally Accepted Accounting
Principles (GAAP). Additional information regarding these measures
may be found in the most recent Management's Discussion and Analysis
report dated February 28, 2013. 
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.
r 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.
Investor Relations
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