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 
CALGARY, ALBERTA -- (Marketwired) -- 03/03/14 --   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:  


 
 
--  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
----------------------------------------------------------------------------
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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.                    

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).  


 
 
--  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                            

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. 


 
 
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
----------------------------------------------------------------------------
 

 
 
(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
----------------------------------------------------------------------------
 

 
 
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%
----------------------------------------------------------------------------

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.  


 
 
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.                                                   

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.  


 
 
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.                                     

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. 


 
 
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
----------------------------------------------------------------------------

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. 


 
 
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
----------------------------------------------------------------------------

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 Comp
any 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: 


 
 
--  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 

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: 


 
 
-----------------------------------------------------------------------
-----
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.  

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. 
Contacts:
Pengrowth
Fred Kerr
Vice President, Investor Relations
Toll free 1-855-336-8814 
Pengrowth
Wassem Khalil
Manager, Investor Relations
Toll free 1-855-336-8814
www.pengrowth.com
 
 
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