Pengrowth Exceeds 2013 Production Guidance on Lower Capital Expenditures and Delivers Strong Reserves Growth

Pengrowth Exceeds 2013 Production Guidance on Lower Capital Expenditures and 
Delivers Strong Reserves Growth 
NEWS RELEASE TRANSMITTED BY Marketwired 
FOR: Pengrowth Energy Corporation 
TSX SYMBOL:  PGF
NYSE SYMBOL:  PGH 
MARCH 3, 2014 
Pengrowth Exceeds 2013 Production Guidance on Lower Capital Expenditures and
Delivers Strong Reserves Growth 
CALGARY, ALBERTA--(Marketwired - March 3, 2014) - Pengrowth Energy Corporation
(TSX:PGF)(NYSE:PGH) is pleased to announce its financial and operating results
for the fourth quarter and the full year 2013, as well as strong 2013 year-end
reserve results. 
Production for the fourth quarter and the full year 2013 was above guidance,
averaging 77,371 barrels of oil equivalent per day (boe/d) and 84,527 boe/d,
respectively. The Company entered 2014 with approximately $450 million of cash
on hand and the financial capacity to complete construction of the first
commercial phase of its Lindbergh thermal bitumen project, with expected first
steam in the fourth quarter of 2014 and first oil in early 2015.  
Improved capital efficiency in the non-thermal business, including an expanded
and highly attractive Cardium drilling program in the Lochend and Garrington
areas, allowed Pengrowth to achieve strong production and cash flow results in
2013. Pengrowth was able to exceed its 2013 production guidance on capital
spending of $696 million, $74 million less than had originally been budgeted.  
Before adjusting for the impacts of the 2013 asset divestitures, Pengrowth
achieved strong reserves growth with: Proved reserves (1P) increasing by 18
percent to 353 million barrels of oil equivalent (MMboe) and Proved plus
Probable reserves (2P) growth of seven percent to 547 MMboe. 
Pengrowth's differentiated strategy focusing on thermal bitumen is
expected to enhance the Company's sustainability by shifting its
production mix towards oil, reducing production decline rates and decreasing
capital reinvestment requirements, thereby generating increased free cash flow
to support dividends and profitable growth projects. 
"2013 was a landmark year for Pengrowth, a year in which we set aggressive
goals and achieved them. We disposed of approximately $1 billion of non-core
assets to fully fund the first commercial phase of the Lindbergh project,
received regulatory approval and began construction of the first phase in
August. We enhanced the capital efficiency of our non-thermal business and
finished the year strongly, with production exceeding guidance, spending $74
million less than budgeted and with $450 million of cash in the bank,"
said Derek Evans, President and CEO of Pengrowth. "In 2014, our primary
objectives will be to get Lindbergh on stream, on time and on budget, maintain
our current dividend, while protecting our balance sheet and continuing to
invest efficiently in our non-thermal oil properties." 
Financial and Operating Highlights:  
/T/ 
--  Pengrowth delivered on its commitments in 2013, including re-positioning 
its asset portfolio and balance sheet to set itself up for first 
production from Lindbergh in early 2015, while maintaining a prudent 
capital structure and dividend plan going forward. 
--  Annual average production of 84,527 boe/d, exceeded guidance and was 
achieved with a non-thermal capital program that was $74 million less 
than originally budgeted. 
--  Successfully divesting approximately $1 billion of assets at excellent 
metrics of approximately $72,000/boe/d allowed Pengrowth to enter 2014 
with approximately $450 million cash on hand and an undrawn, committed 
$1 billion bank facility. 
--  Full year 2013 Funds Flow from Operations of $561 million compared to 
$539 million in 2012. The four percent increase in funds flow compared 
to 2012 resulted from higher realized commodity prices. 
--  Pengrowth replaced 211 percent of 2013 production with organic 2P 
reserve additions, including revisions, of 65 MMboe. 
--  2P reserve life index (RLI) increased to 17.4 years at year-end 2013, an 
18 percent increase from the year-end 2012 RLI of 14.7 years, due 
primarily to increased reserves at Lindbergh. 
--  2013 Finding and Development (F&D) cost was $21.96 per boe including 
changes in Future Development Costs (FDC) for 2P reserves. The 2013 F&D 
costs, excluding changes to FDC were $10.61 per boe for 2P reserves. 
--  Pengrowth's three year weighted average Finding Development and 
Acquisition (FD&A) and F&D costs for 2P reserves were $19.03 per boe and 
$19.07 per boe, respectively, including FDC ($9.76 per boe and $8.43 per 
boe, respectively, excluding FDC). 
--  Crude oil and natural gas liquid (NGL) reserves increased to 65 percent 
of total 1P and 2P reserves, compared to 57 percent and 63 percent of 1P 
and 2P reserves, respectively, at year-end 2012, as a direct result of 
focusing capital on oil and liquids-rich projects, particularly the 
Lindbergh thermal project. 
--  The Lindbergh pilot continues to perform exceptionally well, with 
production volumes from the two well pairs at February 1, 2014 at 
approximately 1,900 bbl/d, with an Instantaneous Steam Oil Ratio (ISOR) 
of approximately 2.0. Total cumulative production from the two pilot 
wells has now exceeded 1.1 million barrels. 
--  Construction of Lindbergh's first commercial phase remains on schedule 
and on budget, with 65 percent of the capital committed or spent as at 
March 3rd, 2014. 
--  Lindbergh reserves increased significantly, with 70 MMbbl and 49 MMbbl 
of 1P and 2P reserve additions, including revisions, respectively, due 
to regulatory approval of the first phase commercial development, 
further delineation drilling and positive pilot results. At year-end 
2013, 1P reserves were 82 MMbbl while 2P reserves stood at 143 MMbbl. 
Over and above the reserve volumes, the best estimate contingent 
resources was an incremental 163 MMbbl.  
Summary of Financial & Operating Results                                     
Three months ended         Twelve months ended     
(monetary amounts in   Dec 31,   Dec 31,      %    Dec 31,    Dec 31,      %
 millions)                2013      2012 Change       2013       2012 Change
----------------------------------------------------------------------------
----------------------------------------------------------------------------
PRODUCTION                                                                  
----------------------------------------------------------------------------
Average daily                                                               
 production (boe/d)    77,371    94,039    (18)    84,527     85,748     (1)
----------------------------------------------------------------------------
FINANCIAL                                                                   
----------------------------------------------------------------------------
Funds flow from                                                             
 operations (1)      $  105.9  $  189.7    (44) $   560.9  $   538.8      4 
----------------------------------------------------------------------------
Funds flow from                                                             
 operations per                                                             
 share               $   0.20  $   0.37    (46) $    1.08  $    1.20    (10)
----------------------------------------------------------------------------
Oil and gas sales                                                           
 including realized                                                         
 commodity risk                                                             
 management (1)      $  328.0  $  431.6    (24) $ 1,538.4  $ 1,480.3      4 
----------------------------------------------------------------------------
Oil and gas sales                                                           
 including realized                                                         
 commodity risk                                                             
 management per boe  $  46.08  $  49.88     (8) $   49.86  $   47.17      6 
----------------------------------------------------------------------------
Operating expense                                                           
 (2)                 $  109.2  $  114.5     (5) $   482.5  $   435.1     11 
----------------------------------------------------------------------------
Operating expense                                                           
 per boe             $  15.34  $  13.23     16  $   15.64  $   13.87     13 
----------------------------------------------------------------------------
Royalty expense      $   62.8  $   69.5    (10) $   275.1  $   277.5     (1)
----------------------------------------------------------------------------
Royalty expense per                                                         
 boe                 $   8.82  $   8.03     10  $    8.92  $    8.84      1 
----------------------------------------------------------------------------
Royalty expense as a                                                        
 percent of sales        18.3%     16.8%             17.3%      19.0%       
----------------------------------------------------------------------------
Operating netback                                                           
 per boe (1) (2)     $  20.82  $  27.87    (25) $   24.35  $   23.67      3 
----------------------------------------------------------------------------
Cash G&A expense (1)                                                        
 (2)                 $   21.7  $   25.1    (14) $    87.8  $    90.1     (3)
----------------------------------------------------------------------------
Cash G&A expense per                                                        
 boe                 $   3.05  $   2.90      5  $    2.85  $    2.87     (1)
----------------------------------------------------------------------------
Capital expenditures $  239.7  $   93.9    155  $   695.8  $   467.4     49 
----------------------------------------------------------------------------
Capital expenditures                                                        
 per share           $   0.46  $   0.18    156  $    1.34  $    1.05     28 
----------------------------------------------------------------------------
Net cash                                                                    
 acquisitions                                                               
 (dispositions)(3)   $  (29.2) $   56.2   (152) $  (977.7) $    86.6        
----------------------------------------------------------------------------
Net cash                                                                    
 acquisitions                                                               
 (dispositions) per                                                         
 share               $  (0.06) $   0.11   (155) $   (1.89) $    0.19        
----------------------------------------------------------------------------
Dividends paid       $   62.4  $   61.0      2  $   248.1  $   289.1    (14)
----------------------------------------------------------------------------
Dividends paid per                                                          
 share               $   0.12  $   0.12      -  $    0.48  $    0.69    (30)
----------------------------------------------------------------------------
Number of shares                                                            
 outstanding at                                                             
 period end (000's)   522,031   511,804      2    522,031    511,804      2 
----------------------------------------------------------------------------
Weighted average                                                            
 number of shares                                                           
 outstanding (000's)  520,910   509,960      2    517,365    447,232     16 
----------------------------------------------------------------------------
STATEMENT OF INCOME                                                         
 (LOSS)                                                                     
---------------------------------------------------------------------       
Adjusted net income                                                         
 (loss) (1)          $  (37.3) $   24.1   (255) $  (183.8) $   (89.7)   105 
----------------------------------------------------------------------------
Net income (loss)(3) $  (91.1) $   (1.0)        $  (316.9) $    12.7        
----------------------------------------------------------------------------
Net income (loss)                                                           
 per share(3)        $  (0.17) $      -         $   (0.61) $    0.03        
----------------------------------------------------------------------------
CASH AND CASH                                                               
 EQUIVALENTS(3)      $   448.5 $     2.7        $   448.5  $     2.7        
----------------------------------------------------------------------------
DEBT (4)                                                                    
----------------------------------------------------------------------------
Long term debt                                  $ 1,412.7  $ 1,530.6     (8)
----------------------------------------------------------------------------
Convertible                                                                 
 debentures                                     $   236.0  $   237.1      - 
----------------------------------------------------------------------------
Total debt excluding                                                        
 working capital                                $ 1,648.7  $ 1,767.7     (7)
----------------------------------------------------------------------------
Total debt including                                                        
 working capital                                $ 1,469.4  $ 1,589.2     (8)
----------------------------------------------------------------------------
CONTRIBUTION BASED                                                          
 ON OPERATING                                                               
 NETBACKS (1) (2)                                                           
----------------------------------------------------------------------------
Light oil                  51%       65%               61%        68%       
----------------------------------------------------------------------------
Heavy oil                  17%       10%               15%        12%       
----------------------------------------------------------------------------
Natural gas liquids        20%       13%               13%        15%       
----------------------------------------------------------------------------
Natural gas                12%       12%               11%         5%       
----------------------------------------------------------------------------
PROVED PLUS PROBABLE                                                        
 RESERVES                                                                   
----------------------------------------------------------------------------
Light oil (Mbbls)                                 103,473    153,229    (32)
----------------------------------------------------------------------------
Heavy oil (Mbbls)                                 172,761    127,454     36 
----------------------------------------------------------------------------
Natural gas liquids                                                         
 (Mbbls)                                           35,091     39,681    (12)
----------------------------------------------------------------------------
Natural gas (Bcf)                                     996      1,150    (13)
----------------------------------------------------------------------------
Total oil equivalent                                                        
 (Mboe)                                           477,385    511,960     (7)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
CAPITAL PERFORMANCE                                                         
----------------------------------------------------------------------------
Finding &                                                                   
 Development Cost                                                           
 (F&D) per boe (5)                              $   21.96  $   16.85     30 
----------------------------------------------------------------------------
Recycle ratio (6)                                     1.1        1.4    (21)
---------------------------------------------------------------------------- 
See disclosures at end of release for definitions of additional GAAP and 
1. Non-GAAP Measures.                                                       
2. Prior periods restated to conform to presentation in the current period. 
3. Percentage changes in excess of 500 are excluded.                        
4. Debt includes the current and long term portions.                         
Includes changes in Future Development Costs (FDC) and based on proved   
5. plus probable reserves.                                                   
Recycle ratio is calculated as operating netback per boe divided by F&D  
6. costs per boe based on proved plus probable reserves.                     
/T/ 
Production  
Pengrowth's fourth quarter average production of 77,371 boe/d came in
above guidance of 75,000 to 77,000 boe/d. Compared to fourth quarter 2012
average production of 94,039 boe/d, fourth quarter 2013 production declined 18
percent, primarily as a result of the sale of properties in 2013. 
Full year 2013 average production of 84,527 boe/d also came in above guidance
of 82,000 to 84,000 boe/d despite a non-thermal capital investment that was $74
million lower than budgeted. Compared to 2012 full year average production of
85,748 boe/d, 2013 production declined by one percent. Successful drilling at
Lochend and Garrington in the Cardium formation underscored the efficiency of
Pengrowth's non-thermal investments.  
Capital Expenditures 
Fourth quarter capital expenditures were approximately $240 million, with 87
percent of expenditures being directed to drilling, completions and facilities,
with the remaining 13 percent spent on maintenance, land, seismic and other
capital. Pengrowth participated in the drilling of 14 (8.3 net) non-thermal
wells and 10 (10 net) wells (7 horizontal producers and 3 delineation/core
holes) at Lindbergh during the quarter.  
Full year 2013 capital spending of $696 million was ten percent lower than the
original budget of $770 million. Similar to the fourth quarter, approximately
87 percent of the full year capital expenditures were allocated to drilling,
completions and facilities and the remaining 13 percent spent on maintenance,
land, seismic, and other capital. Pengrowth participated in the drilling of 139
(79.4 net) non-thermal wells and 36 (36 net) wells (7 horizontal producers, 19
delineation/core holes, 9 observation and 1 water disposal) at Lindbergh.  
Pengrowth reduced capital investment in its non-thermal program and was still
able deliver above the top end of its full year production guidance as a result
of improving capital reinvestment efficiencies and strong drilling results in
the Cardium. Pengrowth's non-thermal capital strategy involves selecting
projects from its large prospect inventory that maximize near term cash flow,
allow strong capital efficiencies and provide the quickest payout of capital
dollars.  
Lindbergh 
Lindbergh is Pengrowth's 100 percent owned and operated thermal project,
located in the Cold Lake area of eastern Alberta. The project offers Pengrowth
the potential to develop production up to 50,000 bbl/d of bitumen over the next
five years. Lindbergh's expected strong netbacks, low decline rates, long
reserve life and low sustaining capital requirements are expected to be the
foundation of Pengrowth's sustainable total return model, supporting
future growth in cash flow per share and underpinning an attractive dividend. 
Pengrowth's Lindbergh pilot delivered another strong year of results that
demonstrated better than expected steam/oil and diluent blending ratios and
stronger than expected production performance. Production from the two well
pair pilot averaged 1,700 bbl/d during the fourth quarter, with cumulative
production from the pilot surpassing one million barrels of bitumen by December
31, 2013. During the quarter, replacement of a pump on one of the producing
wells temporarily reduced production, which has now returned to normal, with
rates of approximately 1,900 bbl/d. The pilot wells are expected to begin their
natural declines in 2014.  
Pengrowth invested $136 million at Lindbergh in the fourth quarter, bringing
the full year 2013 investment to $306 million, consistent with guidance. Civil
and mechanical field construction, as well as shop fabrication of major and
minor equipment components, continued for the first 12,500 bbl/d commercial
phase. Tank construction and major equipment foundations are progressing as
planned and shop fabricated modular equipment continues to be shipped to the
site and set into place. Drilling from the first well-pad continued, with seven
horizontal wells drilled in the fourth quarter and the pad completed in January
2014.  
Capital spent or committed at Lindbergh is now approximately 65 percent of the
budgeted total. The project remains on budget and on schedule, with first steam
from the commercial project planned in the fourth quarter of 2014 and first oil
in early 2015. 
In December of 2013, Pengrowth filed its Environmental Impact Assessment (EIA)
application for regulatory approval of an incremental 17,500 bbl/d expansion at
Lindbergh. Approval of the EIA application is expected in early 2016.  
Non-thermal Oil and Gas  
Pengrowth's significant non-thermal oil and gas portfolio includes a
large, contiguous land base in the Greater Olds/Garrington area, encompassing
over 500 gross (250 net) sections of land, with opportunities in the Cardium,
Viking and Mannville sands as well as in the Mississippian carbonate section.
The extensive, existing gathering and processing infrastructure provides an
efficient platform for continued development in this area. Pengrowth also
controls large conventional oil and gas accumulations in the Swan Hills area,
with low decline production, strong cash flow and future development
opportunities. 
During the fourth quarter, Pengrowth invested $104 million in its non-thermal
assets, with 70 percent of the expenditures being directed to development
activities. Pengrowth continued to achieve strong drilling and completion
results with 14 (8.3 net) wells being drilled in the Cardium formation with 100
percent success. Based on initial test data and early production results, the
Cardium wells appear to be meeting or exceeding type curve expectations. 
For the full year 2013, Pengrowth invested approximately $390 million in its
non-thermal assets, $74 million lower than budgeted. Approximately 77 percent
of this investment was directed to development activities, primarily in the
Greater Olds/Garrington area. Pengrowth participated in the drilling of 139
(79.4 net) non-thermal wells in 2013.  
Operating Expenses 
Fourth quarter 2013 operating expenses were $109 million ($15.34 per boe)
compared to $115 million ($13.23 per boe) for the same period of 2012.  
Full year operating expenses of approximately $483 million ($15.64 per boe)
were 11 percent higher on an aggregate basis compared to 2012 expenses of $435
million ($13.87 per boe). Higher power costs, the inclusion of the Lindbergh
thermal pilot expenses in 2013 results and higher processing and gathering fees
were the primary contributors to the higher operating expenses in 2013. On a
per boe basis, 2013 operating expenses increased $1.77/boe compared to 2012,
due to the higher costs noted above and slightly lower production volumes as a
result of the 2013 dispositions. 
Funds Flow from Operations  
Fourth quarter 2013 Funds Flow from Operations was $106 million ($0.20 per
share) compared to $190 million ($0.37 per share) in the fourth quarter 2012.
The 44 percent decrease in Funds Flow from Operations, when comparing the
fourth quarter to the same period in 2012, was largely due to an 18 percent
decrease in production volumes as a result of the 2013 dispositions and higher
oil price differentials experienced in the quarter. The widening of light and
heavy oil price differentials experienced in November and December reduced
revenues and funds flow during the quarter by approximately $39 million
compared to the fourth quarter of 2012.  
Full year 2013 Funds Flow from Operations was $561 million ($1.08 per share)
compared to $539 million ($1.20 per share) in 2012. The four percent increase
in aggregate funds flow compared to 2012 resulted from higher commodity prices,
partly offset by higher operating expenses year over year. 
Adjusted Net Income (Loss) 
Pengrowth recorded an adjusted net loss of $37 million in the fourth quarter
and $184 million for the full year, largely as a result of one-time, non-cash
losses on dispositions and realized commodity risk management losses. These
compare to adjusted net income of $24 million in the fourth quarter of 2012 and
adjusted net loss of $90 million for the full year 2012. See the
Management's Discussion and Analysis accompanying Pengrowth's 2013
year-end financial statements for details. The Company continues to seek cash
flow certainty by entering into commodity risk management contracts to ensure
the financial flexibility to fund Lindbergh, pay its monthly dividend and
continue to invest in its non-thermal oil assets.  
Summary of Reserves Results  
Pengrowth's reserves and present values at year-end 2013 were based on an
independent engineering evaluation conducted by GLJ Petroleum Consultants Ltd.
(GLJ) effective December 31, 2013, using the GLJ January 1, 2014 price forecast
and prepared in accordance with National Instrument 51-101 (NI 51-101) and the
Canadian Oil and Gas Evaluation Handbook (COGEH).  
/T/ 
--  Pengrowth's year-end 2013 2P reserves, after the impacts of the 2013 
dispositions, were 477 MMboe compared to 512 MMboe at year-end 2012. 
--  The 6.8 percent decrease in 2P reserves compared to December 31, 2012 
resulted from net asset dispositions of 69 MMboe and production of 31 
MMboe, offset by a combination of drilling activity and increased 
reserve bookings at Lindbergh, which added 65 MMboe. 
--  Total proved reserves at 2013 year-end, increased 2.3 percent to 307 
MMboe from 300 MMboe at year-end 2012. 
--  On a 1P basis, Pengrowth replaced 122 percent of 2013 production, adding 
38 MMboe of 1P reserves net of dispositions. 
--  Pengrowth's total proved reserves of 307 MMboe account for 64 percent of 
total 2P reserves. 
--  Proved producing reserves of 186 MMboe represent approximately 60 
percent of the total proved reserves. 
--  Using a 6:1 boe conversion rate for natural gas, approximately 22 
percent of 2P reserves are light/medium crude oil, 36 percent are heavy 
oil and bitumen, seven percent are NGL and 35 percent are natural gas. 
--  Proved producing reserves and total proved reserves account for 53 and 
74 percent respectively, of the 2P reserves before tax present value of 
$5.1 billion.   
Table 1. Company Interest Reserves Summary(i)                               
As at December 31, 2013                                                     
---------------------------------------------------------------------------- 
Light &                                                      
Medium                Natural                               
crude  Heavy             Gas Natural  Total oil Percent of 
oil    oil Bitumen Liquids     Gas equivalent     2P oil 
(Mbbl) (Mbbl)  (Mbbl)  (Mbbl)   (Bcf)     (Mboe) equivalent
----------------------------------------------------------------------------
Proved                                                                      
 Producing       57,926 13,273   1,304  23,587   537.9    185,743        39%
Proved                                                                      
 Developed Non-                                                             
 producing          596     83       -     449    18.7      4,238         1%
Proved                                                                      
 Undeveloped     14,771  5,955  80,423   1,306    87.5    117,035        25%
----------------------------------------------------------------------------
Total Proved     73,293 19,311  81,727  25,342   644.1    307,016        64%
Total Probable   30,180 10,884  60,838   9,749   352.3    170,369        36%
----------------------------------------------------------------------------
Total Proved                                                                
 Plus Probable  103,473 30,196 142,565  35,091   996.4    477,385       100%
----------------------------------------------------------------------------
(i) Numbers in table may not add due to rounding                             
/T/ 
Reserves Reconciliation  
Total 2P reserve additions of 65 MMboe, including revisions, resulted from
drilling and improved recovery projects, replacing production by 211 percent.
The most significant of these additions were reserves attributed to the
Lindbergh thermal project, where 2P reserves increased by 49 MMboe in 2013 over
year-end 2012 numbers. 
Non-core asset dispositions resulted in a 2P reserve decrease of 70 MMboe in
2013, partially offset by minor acquisitions of 1 MMboe. As a result of the
large disposition program, total 2P reserves at year-end 2013 decreased by 6.8
percent compared to year-end 2012. 
On a 1P basis, year-end 2013 reserves increased by 2.3 percent compared to
2012. In total, 38 MMboe of 1P reserves were added, including revisions and net
of dispositions, replacing 122 percent of 2013 production. 
/T/ 
Table 2. Company Interest Reserves Reconciliation 2013(i)                   
---------------------------------------------------------------------------- 
Light &                                            
Medium                 Natural                    
crude   Heavy             Gas Natural  Total oil 
oil     oil Bitumen Liquids     Gas equivalent 
(Mbbl)  (Mbbl)  (Mbbl)  (Mbbl)   (Bcf)     (Mboe)
----------------------------------------------------------------------------
Total Proved                                                                
December 31, 2012         107,841  21,687  12,789  28,425   776.0    300,078
Technical Revisions           302     833     324   1,362    12.7      4,943
Economic Factors             (10)    (23)       0    (40)   (2.4)      (473)
Drilling                    5,379     634  69,287     978    15.5     78,860
Improved Recovery              30       0       0      14     0.2         83
Acquisitions                  311      61       0     150     1.8        816
Dispositions             (30,683) (1,504)       0 (1,724)  (75.2)   (46,439)
Production                (9,877) (2,376)   (674) (3,824)  (84.6)   (30,852)
----------------------------------------------------------------------------
December 31, 2013          73,293  19,311  81,727  25,342   644.1    307,016
----------------------------------------------------------------------------
Total Proved Plus                                                           
 Probable                                                                   
December 31, 2012         153,229  32,662  94,792  39,681 1,149.6    511,960
Technical Revisions       (2,168)   (298)     272     977     8.4        181
Economic Factors             (58)    (37)       0    (94)   (4.1)      (870)
Drilling                    6,557   2,282  48,176   1,255    45.1     65,783
Improved Recovery              69       0       0      23     0.5        174
Acquisitions                  409      76       0     183     2.2      1,030
Dispositions             (44,687) (2,115)       0 (3,109) (120.7)   (70,020)
Production                (9,877) (2,376)   (674) (3,824)  (84.6)   (30,852)
----------------------------------------------------------------------------
December 31, 2013         103,473  30,196 142,565  35,091   996.4    477,385
---------------------------------------------------------------------------- 
/T/ 
/T/ 
(i) Numbers in table may not add due to rounding                             
Table 3. Select prices from GLJ's January 1, 2014 forecast prices and       
 inflation rates                                                            
---------------------------------------------------------------------------- 
WTI Crude   Edm Light   WCS Crude  Natural Gas   Inflation 
Oil   Crude Oil         Oil      at AECO        Rate
Year              ($US/bbl)  ($Cdn/bbl)  ($Cdn/bbl) ($Cdn/MMBtu)    (%/year)
----------------------------------------------------------------------------
2013 (actual)         97.88       93.33       74.91         3.24           -
2014                  97.50       92.76       75.60         4.03         2.0
2015                  97.50       97.37       79.36         4.26         2.0
2016                  97.50      100.00       81.50         4.50         2.0
2017                  97.50      100.00       81.50         4.74         2.0
2018                  97.50      100.00       81.50         4.97         2.0
2019                  97.50      100.00       81.50         5.21         2.0
2020                  98.54      100.77       82.13         5.33         2.0
2021                 100.51      102.78       83.76         5.44         2.0
2022                 102.52      104.83       85.44         5.55         2.0
2023                 104.57      106.93       87.14         5.66         2.0
----------------------------------------------------------------------------
Thereafter        +2.0 %/yr   +2.0 %/yr   +2.0 %/yr    +2.0 %/yr         2.0
---------------------------------------------------------------------------- 
/T/ 
/T/ 
Table 4. Before Income Tax Net Present Value Summary                        
As at December 31, 2013                                                     
---------------------------------------------------------------------------- 
Discounted at          Percent of 2P 
------------------------                  
($ millions, except                                                         
 percentages)         Undiscounted    5%   10%   15%   20% Discounted at 10%
----------------------------------------------------------------------------
Proved Producing             4,369 3,358 2,742 2,333 2,043               53%
Proved Developed Non-                                                       
 producing                      80    52    38    30    24                1%
Proved Undeveloped           2,952 1,719 1,052   661   416               20%
----------------------------------------------------------------------------
Total Proved                 7,401 5,129 3,832 3,024 2,483               74%
Total Probable               5,372 2,392 1,316   841   593               26%
----------------------------------------------------------------------------
Total Proved Plus                                                           
 Probable                   12,774 7,521 5,148 3,865 3,076              100%
---------------------------------------------------------------------------- 
/T/ 
Net Asset Value 
The following table provides a calculation of Pengrowth's estimated net
asset value (NAV) based on the estimated future net revenues associated with
Pengrowth's proved plus probable reserves.  
/T/ 
Table 5. Net Asset Value - Before Income Tax                                
As at December 31, 2013                                                     
----------------------------------------------------------------------------
($ millions, except percentages and share                                   
 numbers)                                          5% Discount  10% Discount
----------------------------------------------------------------------------
Value of Total Proved plus Probable reserves(1)                              
7,521         5,148
Undeveloped Land(2)                                        184           184
Long-term debt, including convertible debentures                            
 and working capital(3)                                (1,452)       (1,452)
Reclamation Funds(4)                                        55            55
Other Liabilities (Asset Retirement Obligations,                            
 commodity contracts, private investment)(5)             (148)          (10)
----------------------------------------------------------------------------
Net Asset Value                                          6,160         3,925
Shares outstanding (millions)                              522           522
----------------------------------------------------------------------------
NAV per share ($/share)                                  11.80          7.52
---------------------------------------------------------------------------- 
1. Discounted value of GLJ total proved plus probable reserves.             
2. Internal undeveloped land value estimate.                                
3. See 2013 Audited Financial Statements and Notes.                          
Pre-paid reclamation costs for Sable Offshore Energy Project, Nova Scotia
4. and Judy Creek, Alberta.                                                  
Estimated value of commodity contracts, ownership in a private company   
5. and other liabilities.                                                    
/T/ 
As of December 31, 2013, Pengrowth's estimated NAV is $7.52/share. The 13
percent decrease from the 2012 year-end estimated NAV of $8.61/share is
primarily due to a lower reserve value resulting from significant asset
dispositions in 2013 and higher forecasted FDC. 
Finding, Development and Acquisition Costs  
During 2013, Pengrowth spent $692 million, excluding information technology and
office expenditures, on development and optimization activities, which added 83
MMboe of 1P and 65 MMboe of 2P reserves including revisions, resulting in a 2P
F&D cost of $21.96 (including FDC). The largest 2P additions were at
Lindbergh, where 2P reserves increased by 49 MMboe due to further delineation
drilling and continued superior pilot performance. 
Pengrowth's 2013 F&D and FD&A costs are summarized below. These
are determined separately for exploration and development activities,
acquisition and disposition transactions, and with and without the change in
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.  
/T/ 
Table 6. 2013 F&D and FD&A Costs                                            
---------------------------------------------------------------------------- 
2011 - 2013   
2013              2012       Weighted Average 
------------------- ---------------- ---------------- 
Proved           Proved           Proved 
plus             plus             plus 
Proved  Probable  Proved Probable  Proved Probable
---------------------- ------------------- ---------------- ---------------- 
Costs Excluding Future                                                      
 Development Costs                                                          
----------------------                                                       
Exploration and                                                             
 Development Capital                                                        
 Expenditures - $MM        692.4     692.4   461.0    461.0 1,756.8  1,756.8
Exploration and                                                             
 Development Reserve                                                        
 Additions including                                                        
 Revisions - MMboe          83.4      65.3    21.0    103.8   145.5    208.4
---------------------- ------------------- ---------------- ----------------
Finding and                                                                 
 Development Cost -                                                         
 $/boe                      8.30     10.61   21.93     4.44   12.08     8.43
---------------------- ------------------- ---------------- ----------------
---------------------- ------------------- ---------------- ----------------
F&D Recycle Ratio, $/$       2.9       2.3     1.1      5.3     2.1      3.0
---------------------- ------------------- ---------------- ---------------- 
Net Acquisition                                                             
 (Disposition) Capital                                                      
 - $MM                   (977.8)   (977.8) 1,654.2  1,654.2   668.1    668.1
Net Acquisition                                                             
 (Disposition) Reserve                                                      
 Additions - MMboe        (45.6)    (69.0)    75.9    109.4    30.1     40.1
---------------------- ------------------- ---------------- ----------------
Net Acquisition Cost -                                                      
 $/boe                     21.43     14.17   21.81    15.12   22.21    16.64
---------------------- ------------------- ---------------- ---------------- 
Total Capital                                                               
 Expenditures                                                               
 including Net                                                              
 Acquisitions                                                               
 (Dispositions) - $MM    (285.3)   (285.3) 2,115.2  2,115.2 2,424.9  2,424.9
Reserve Additions                                                           
 including Net                                                              
 Acquisitions                                                               
 (Dispositions) -                                                           
 MMboe                      37.8     (3.7)    96.9    213.2   175.6    248.5
---------------------- ------------------- ---------------- ----------------
Finding Development                                                         
 and Acquisition Cost                                                       
 - $/boe(1 )              (7.55)     76.66   21.83     9.92   13.81     9.76
---------------------- ------------------- ---------------- ---------------- 
Costs Including Future                                                      
 Development Costs                                                          
----------------------                                                       
Exploration and                                                             
 Development Capital                                                        
 Expenditures - $MM        692.4     692.4   461.0    461.0 1,756.8  1,756.8
Exploration and                                                             
 Development Change in                                                      
 FDC - $MM               1,031.7     741.2   104.6  1,288.0 1,393.3  2,217.1 
------------------- ---------------- ----------------
Exploration and                                                             
 Development Capital                                                        
 including Change in                                                        
 FDC - $MM               1,724.1   1,433.6   565.6  1,748.9 3,150.1  3,973.9
Exploration and                                                             
 Development Reserve                                                        
 Additions including                                                        
 Revisions - MMboe          83.4      65.3    21.0    103.8   145.5    208.4
---------------------- ------------------- ---------------- ----------------
Finding and                                                                 
 Development Cost -                                                         
 $/boe                     20.67     21.96   26.91    16.85   21.65    19.07
---------------------- ------------------- ---------------- ----------------
---------------------- ------------------- ---------------- ----------------
F&D Recycle Ratio, $/$       1.2       1.1     0.9      1.4     1.2      1.3
---------------------- ------------------- ---------------- ---------------- 
Net Acquisition                                                             
 (Disposition) Capital                                                      
 - $MM                   (977.8)   (977.8) 1,654.2  1,654.2   668.1    668.1
Net Acquisition                                                             
 (Disposition) FDC -                                                        
 $MM                     (224.7)   (381.2)   229.8    467.2     5.1     86.0 
------------------- ---------------- ----------------
Net Acquisition                                                             
 (Disposition) Capital                                                      
 including Change in                                                        
 FDC - $MM             (1,202.5) (1,359.0) 1,884.0  2,121.4   673.3    754.2
Net Acquisition                                                             
 (Disposition) Reserve                                                      
 Additions - MMboe        (45.6)    (69.0)    75.9    109.4    30.1     40.1
---------------------- ------------------- ---------------- ----------------
Net Acquisition Cost -                                                      
 $/boe                     26.36     19.70   24.83    19.39   22.38    18.79
---------------------- ------------------- ---------------- ---------------- 
Total Capital                                                               
 Expenditures                                                               
 including Net                                                              
 Acquisitions                                                               
 (Dispositions) - $MM    (285.3)   (285.3) 2,115.2  2,115.2 2,424.9  2,424.9
Total Change in FDC -                                                       
 $MM                       807.0     360.0   334.4  1,755.2 1,398.4  2,303.2 
------------------- ---------------- ----------------
Total Capital                                                               
 including Change in                                                        
 FDC - $MM                 521.7      74.6 2,449.6  3,870.4 3,823.3  4,728.1
Reserve Additions                                                           
 including Net                                                              
 Acquisitions                                                               
 (Dispositions) -                                                           
 MMboe                      37.8     (3.7)    96.9    213.2   175.6    248.5
---------------------- ------------------- ---------------- ----------------
Finding Development                                                         
 and Acquisition Cost                                                       
 including FDC -                                                            
 $/boe(2)                  13.80   (20.05)   25.29    18.16   21.78    19.03
---------------------- ------------------- ---------------- ---------------- 
2011 - 2013 
2013  2012 (Restated) Weighted Average 
------------------- ---------------- ----------------
Operating Netback                                                           
 ($/boe)(3)                          24.35            23.67            25.52
---------------------------------------------------------------------------- 
1. The negative 2013 FD&A Cost excluding FDC for Proved Reserves is due to   
the proceeds from dispositions exceeding capital expenditures plus        
acquisition costs.                                                       
2. The negative 2013 FD&A Cost including FDC for P+P Reserves is due to the  
reserve decrease from dispositions exceeding the reserve additions,       
including revisions, from development activity and acquisitions.         
3. The operating netbacks are equal to sales revenue plus other income less  
royalties, operating expenses and transportation costs. Please see        
Pengrowth's 2013 year-end Management Discussion and Analysis (MD&A) and   
Annual Information Form (AIF) dated February 28, 2014 for further         
information.                                                             
4. The aggregate of the exploration and development costs incurred in the    
most recent financial year and the changes during the year in estimated   
future development costs generally will not reflect total finding and     
development costs related to reserve additions for that year.             
Table 7. Total Future Net Revenue (Undiscounted)                            
---------------------------------------------------------------------------- 
Operating Development
($ millions)                       Revenue  Royalties      Costs       Costs
----------------------------------------------------------------------------
Proved Producing                    11,911      2,130      4,917         187
Proved Developed Non-producing         213         34         78          17
Proved Undeveloped                   8,794      1,624      2,376       1,797
----------------------------------------------------------------------------
Total Proved                        20,918      3,788      7,371       2,001
Total Probable                      13,668      2,975      3,883       1,380
----------------------------------------------------------------------------
Total Proved Plus Probable          34,587      6,763     11,254       3,382
---------------------------------------------------------------------------- 
Table 7. Total Future Net Revenue (Undiscounted)                            
---------------------------------------------------------------------------- 
Revenue                Revenue 
Abandonment     Before     Income      After 
($ millions)                      Costs(1) Income Tax     Tax(2)  Income Tax
----------------------------------------------------------------------------
Proved Producing                       308      4,369         28       4,341
Proved Developed Non-producing           4         80         19          61
Proved Undeveloped                      45      2,952        821       2,131
----------------------------------------------------------------------------
Total Proved                           357      7,401        868       6,533
Total Probable                          58      5,372      1,509       3,863
----------------------------------------------------------------------------
Total Proved Plus Probable             415     12,774      2,378      10,396
---------------------------------------------------------------------------- 
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.                                      
/T/ 
Reserve Life Index  
Pengrowth's proved RLI increased to 11.8 years from 9.2 years in 2012. The
RLI for proved plus probable reserves increased to 17.4 years at year-end 2013,
an 18 percent increase from the year-end 2012 RLI of 14.7 years, due primarily
to increased reserves at Lindbergh.  
/T/ 
Table 8. Historical Reserve Life Index                                      
----------------------------------------------------------------------------
Reserve Line Index (Years)                      2013    2012    2011    2010
----------------------------------------------------------------------------
Proved Producing                                 7.4     7.6     7.6     7.2
Total Proved                                    11.8     9.2     9.0     8.2
Total Proved Plus Probable                      17.4    14.7    12.0    11.1
---------------------------------------------------------------------------- 
/T/ 
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.  
Reserves and Contingent Resources Classification  
The following table summarizes GLJ's estimates of reserves and contingent
resources, as of year-end 2013, for the Lindbergh thermal property and
Groundbirch natural gas property. 
/T/ 
Table 9. Summary of Reserves and Contingent Resources                       
---------------------------------------------------------------------------- 
Reserves (MMboe)          Contingent Resources (MMboe) 
---------------------------------------------------------------------------- 
Proved +                               
Proved +    Probable +       Low      Best      High
Field       Proved      Probable      Possible  Estimate  Estimate  Estimate
----------------------------------------------------------------------------
Lindbergh       82           143           196       124       163       276
Groundbirch     10            32            39        36        57       100
---------------------------------------------------------------------------- 
/T/ 
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 regulatory approval for expanding the current development area. It is
expected that GLJ will do a full reserve and resource update for Lindbergh in
the third quarter of 2014, which will incorporate the results of first half
delineation drilling, pilot performance and impact of the EIA application filed
in December 2013 to expand the Lindbergh 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, in
conjunction with higher gas prices is required before Pengrowth can commit to
further development. 
Reserves and contingent resources included herein are stated on a Company
interest basis 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) dated February 28, 2014, which is available on SEDAR at
www.SEDAR.com. 
Financial Flexibility 
Pengrowth remains committed to ensuring its financial health and flexibility
during its transition to becoming a low decline, sustainable, dividend paying,
higher cash flowing thermal energy producer. 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 its Lindbergh thermal project. These
measures include: 
/T/ 
--  Selling approximately $1 billion of non-core properties in 2013. 
--  Reducing indebtedness 
--  Expanding commodity hedging 
--  Managing interest costs through terming out debt at fixed rates  
/T/ 
Following the closing of the non-core dispositions, Pengrowth had approximately
$450 million of cash on hand as at December 31, 2013. These proceeds will be
used to provide the capital for the completion of the first 12,500 bbl/d
commercial phase of Lindbergh, as well as provide Pengrowth with a balanced
cash flow profile through 2014, whereby cash outflows are expected to equal
cash inflows plus cash on hand.  
Pengrowth continues to mitigate commodity price risk and provide a measure of
stability and predictability to cash flows through the utilization of hedging.
At March 3rd, 2014, Pengrowth has 76 percent of its expected 2014 oil
production hedged at Cdn$94.51 per barrel and 62 percent of 2015 expected oil
production hedged at Cdn$93.91 per barrel. Natural gas hedges account for 64
percent of expected 2014 gas production at Cdn$3.81 per Mcf and 49 percent of
2015 expected production hedged at Cdn$3.85 per Mcf. Pengrowth also hedges
portions of its power consumption in order to mitigate volatility in operating
expenses. Pengrowth has hedged 78 percent of expected 2014 power consumption at
$55.69/MWh and 61 percent of expected 2015 power consumption at $49.50/MWh.  
Additional details of Pengrowth's risk management contracts in place for
2014, 2015 and 2016 are outlined in the Management's Discussion and
Analysis and accompanying Notes to the December 31, 2013 Audited Financial
Statements.  
Pengrowth's total long-term debt was approximately $1.6 billion as at
December 31, 2013, comprising $1.4 billion of fixed rate term notes and $0.2
billion of convertible debentures. At December 31, 2013, Pengrowth's $1.0
billion bank facility continued to be undrawn and the company had approximately
$450 million of cash on hand.  
2014 Capital Expenditures 
The 2014 capital program will once again target the development of light oil
and liquids-rich natural gas production, while continuing to invest in the
commercial development of the Lindbergh project. Pengrowth has budgeted $350
million for non-thermal activities, mainly in the Greater Olds/Garrington area
and on heavy oil assets in the Jenner and Bodo areas. The 2014 non-thermal
budget will focus on projects with the highest rates of return, shortest
payouts and maximum funds flow.  
At Lindbergh, $365 million has been budgeted for 2014, which includes the
completion of the central processing facility, drilling the remaining 16 well
pairs for the first 12,500 bbl/d commercial phase and investment to facilitate
incremental production in 2016.  
A summary of Pengrowth's 2014 operating and financial guidance is provided
below: 
/T/ 
----------------------------------------------------------------------------
Average daily production volume (boe/d)                     71,000 to 73,000
Total capital expenditures ($millions)                            700 to 730
Royalties (% of sales)                                              16 to 18
Net operating costs ($ per boe)(1)                            15.20 to 15.80
Cash G & A expense ($ per boe)(1)                               2.70 to 2.90
Funds flow from operations ($ per share)(2)                     0.95 to 1.05
---------------------------------------------------------------------------- 
1. Per boe estimates based on high and low ends of production guidance.      
Based on mid-point of production guidance using WTI USD$95/bbl, 8%       
2. discount for light oil and 21% discount for heavy oil, $3.50/Mcf AECO and 
$0.95 USD/CAD FX rate and approximately 525 million shares outstanding.   
/T/ 
Outlook 
Pengrowth continues on its transition to becoming a sustainable, low decline,
dividend paying, higher cash flowing thermal energy producer. In 2014, the
primary objectives will be to maintain Pengrowth's dividend at the current
level of four cents per share per month, while continuing to execute on the
commercial development of the Lindbergh thermal project, ensuring Lindbergh is
on time, on budget and en route to first steam in the fourth quarter of 2014,
with meaningful oil production in early 2015. Pengrowth will invest in its best
opportunities, maximizing funds flow from its non-thermal business, while
continuing to be prudent in managing its balance sheet and maintaining
financial flexibility.  
Pengrowth's audited Financial Statements for the three and twelve months
ended December 31, 2013 and related Management's Discussion and Analysis,
as well as Pengrowth's AIF dated February 28, 2014, can be viewed on
Pengrowth's website at www.pengrowth.com. They will also be available on
SEDAR at www.sedar.com and on EDGAR at www.sec.gov/edgar.shtml.  
Conference call:  
Pengrowth will host a conference call for investors at 6:30 A.M. Mountain Time
on Monday, March 3, 2014. To participate, callers may dial in via telephone or
participate online in listen only mode via the audio webcast. To ensure timely
participation in the teleconference, callers are encouraged to dial in 10
minutes prior to commencement of the call to register. 
Dial-in numbers:  
Toll free: (866) 223-7781 or Toronto local (416) 340-2216  
Live listen only audio webcast: http://www.gowebcasting.com/5262 
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 Cardium light oil, Lindbergh thermal
bitumen and Swan Hills light oil 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 
For further information about Pengrowth, please visit our website
www.pengrowth.com or contact: Investor Relations, E-mail:
investorrelations@pengrowth.com 
Currency: 
All amounts are stated in Canadian dollars unless otherwise specified. 
Advisory Regarding Reserves, Contingent Resources and Production Information 
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, 2014 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 does 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 revenue for all
properties, due to effects of aggregation. 
Possible reserves are those additional reserves that are less certain to be
recovered than probable reserves. There is a 10 percent probability that the
quantities actually recovered will equal or exceed the sum of proved plus
probable plus possible reserves. 
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 thermal oil 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 ten percent confidence level. The
Contingent Resources as disclosed herein are considered economic based on
forecast prices and costs as at December 31, 2013. Additional information
relating to the Contingent Resources estimate for Pengrowth's Lindbergh
thermal oil 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, 2014, which
can be accessed immediately on Pengrowth's website at www.pengrowth.com
and has been filed on SEDAR at www.sedar.com and on Form 40-F on EDGAR at
www.sec.gov/edgar.shtml. 
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.  
Caution Regarding Forward Looking Information:  
In the interest of providing our shareholders and potential investors with
information regarding us, including management's assessment of our future
plans and operations, certain statements in this press release are
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 future dividends;
2014 anticipated capital expenditures and the allocation thereof; the
Company's non-thermal capital strategy; Lindbergh development being on
time and on budget; bringing Lindbergh on stream; ability of Lindbergh to
generate cash flow; timing of Lindbergh development; Lindbergh production
potential; future declines on Lindbergh pilot wells; expected average daily
production; expected decline rates, reserve life and capital requirements of
Lindbergh; expected first steam and production from the first commercial phase
of Lindbergh; timing for approval of the Company's environmental impact
assessment; anticipated timing for a reserves and resources update at
Lindbergh; planned financial flexibility; benefit of commodity risk management
program; improved capital efficiencies to be realized in 2014; number of wells
to be drilled at Lindbergh in 2014; assumptions as to future commodity prices,
discounts and exchange rates; future expansion of Lindbergh facility to
accommodate additional commercial production; recycle ratios; number of rigs
operating; future production declines and free cash flow; financing plans;
adjusted payout ratio; net operating costs for 2014; anticipated G&A
expenses; 2014 guidance including average daily production, total capital
expenditures, royalties, net operating costs, cash flow, cash G&A and funds
flow from operations per share; plans to manage interest costs by terming out
debt at fixed rates. 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 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; 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 our Annual
Information Form dated February 28, 2014.  
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 and Non-IFRS Measures  
In addition to providing measures prepared in accordance with International
Financial Reporting Standards (IFRS), Pengrowth presents additional and
non-IFRS measures, Adjusted Net Income (Loss), operating netbacks, adjusted
payout ratio 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 measures are
provided, in part, 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 (loss), cash provided by operations and other measures of
financial performance and liquidity reported in accordance with IFRS. Further
information with respect to these additional and non-IFRS measures can be found
in Pengrowth's most recent management's discussion and analysis. 
Note to US Readers 
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. 
Current SEC reporting requirements permit, but do not require United States 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.
The SEC does not permit the inclusion of estimates of contingent resources in
reports filed with it by United States companies. 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 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. 
-30-
FOR FURTHER INFORMATION PLEASE CONTACT: 
Pengrowth
Fred Kerr
Vice President, Investor Relations
Toll free 1-855-336-8814
or
Pengrowth
Wassem Khalil
Manager, Investor Relations
Toll free 1-855-336-8814 
INDUSTRY:  Energy and Utilities - Oil and Gas  
SUBJECT:  OEX 
-0-
-0- Mar/03/2014 13:00 GMT
 
 
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