Peyto Announces Q4 and Year End 2012 Report to Shareholders With Corrected Funds from Operations

Peyto Announces Q4 and Year End 2012 Report to Shareholders With Corrected 
Funds from Operations 
CALGARY, ALBERTA -- (Marketwire) -- 03/06/13 -- Peyto Exploration &
Development Corp. (TSX:PEY) ("Peyto" or the "Company") is pleased to
report operating and financial results for the fourth quarter and the
2012 fiscal year. Peyto grew production and reserves per share to
record levels in 2012 while delivering a 76% operating margin(1) and
a 23% profit margin(2). An 8% return on capital and an 8% return on
equity were achieved despite historically low natural gas prices.
Highlights for 2012 include: 


 
--  Production per share up 17%. Annual production increased 26% or 17% per
    share to 267 MMCFe/d (44,527 boe/d) in 2012 from 213 MMCFe/d (35,465
    boe/d) in 2011. Q4 2012 production was also up 26% to 49,754 boe/d. 
--  Reserves per share up 15%. Proved Producing ("PP"), Total Proved ("TP")
    and Proved plus Probable Additional ("P+P") reserves increased 24%, 23%,
    and 22% (15%, 14%, and 13% per share) to 0.9, 1.7, and 2.4 TCFe,
    respectively. 
--  Reduced cash costs 22%. Royalties, operating costs, transportation, G&A
    and interest expense totaled $1.05/MCFe ($6.30/boe) in 2012 down from
    $1.35/MCFe ($8.10/boe) in 2011. Industry leading operating costs were
    just $0.32/MCFe ($1.92/boe) in 2012. 
--  Funds from Operations per share of $2.19. Generated $309 million in
    Funds from Operations ("FFO") in 2012, down 7% from $2.36/share in 2011
    despite a 27% drop in realized commodity prices. 
--  Capital investments up 63%. Invested a record $452 million to build
    25,700 boe/d at a cost of $17,600/boe/d and invested $166 million to
    acquire Open Range Energy Corp. ("Open Range"), which produced 4,300
    boe/d at year end, for a cost of $38,600/boe/d. Average cost to add new
    production was $20,600/boe/d. 
--  P+P FD&A half the field netback. All in FD&A cost for PP, TP and P+P
    reserves was $2.22/MCFe, $2.04/MCFe and $1.68/MCFe ($10.07/boe),
    respectively including changes in Future Development Capital ("FDC"),
    while the average field netback was $3.46/MCFe ($20.75/boe). 
--  NAV per share of $34. Net Asset Value or the Net Present Value per
    share, debt adjusted (discounted at 5%) of the P+P reserves was
    $20/share of developed reserves and $14/share of undeveloped reserves. 
--  Earnings of $0.67/share and dividends of $0.72/share. A total of $94
    million in earnings were generated and $102 million in dividends were
    paid to shareholders. Cumulative dividend/distribution payments made by
    Peyto to date total $1.3 Billion ($12.31/share). 

 
2012 in Review 
The year 2012 was an historic year for Peyto. With the largest
capital program in the Company's history, coupled with its first
major corporate acquisition, Peyto added a record 30,000 boe/d of new
production. Peyto again led the industry as the lowest cost producer
and with this advantage was able to generate a 23% profit margin
despite natural gas prices that dropped to their lowest level in
Company history. In addition to growing production and reserves per
share, Peyto increased its ownership and control of processing
infrastructure by 100 mmcf/d or 30%, ensuring this low cost advantage
can continue in the future. Peyto's land position in the Alberta Deep
Basin also grew by more than 30% resulting in the addition of 1.6 new
booked horizontal drilling locations for every well drilled in 2012.
Production revenues were maximized with the installation of Peyto's
enhanced NGL extraction facilities at the Company's Oldman gas plant.
Peyto's profitable, returns driven strategy once again delivered an
attractive total return on shareholder's capital in 2012.  


 
(1) Operating Margin is defined as Funds from Operations divided by Revenue 
    before Royalties but including realized hedging gains (losses).         
(2) Profit Margin is defined as Net Earnings for the year divided by Revenue
    before Royalties but including realized hedging gains (losses). Natural 
    gas volumes recorded in thousand cubic feet (mcf) are converted to      
    barrels of oil equivalent (boe) using the ratio of six (6) thousand     
    cubic feet to one (1) barrel of oil (bbl). Natural gas liquids and oil  
    volumes in barrel of oil (bbl) are converted to thousand cubic feet     
    equivalent (mcfe) using a ratio of one (1) barrel of oil to six (6)     
    thousand cubic feet. This could be misleading if used in isolation as it
    is based on an energy equivalency conversion method primarily applied at
    the burner tip and does not represent a value equivalency at the        
    wellhead.                                                               
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                                       3 Months Ended December 31        %  
                                              2012           2011   Change  
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Operations                                                                  
Production                                                                  
 Natural gas (mcf/d)                       266,808        212,715       25% 
 Oil & NGLs (bbl/d)                          5,286          3,947       34% 
 Thousand cubic feet equivalent                                             
  (mcfe/d @ 1:6)                           298,522        236,394       26% 
 Barrels of oil equivalent (boe/d @                                         
  6:1)                                      49,754         39,399       26% 
Product prices                                                              
 Natural gas ($/mcf)                          3.45           4.21      (18)%
 Oil & NGLs ($/bbl)                          73.01          88.04      (17)%
 Operating expenses ($/mcfe)                  0.31           0.35      (11)%
 Transportation ($/mcfe)                      0.11           0.12       (8)%
 Field netback ($/mcfe)                       3.62           4.32      (16)%
 General & administrative expenses                                          
  ($/mcfe)                                    0.02           0.05      (60)%
 Interest expense ($/mcfe)                    0.32           0.35       (9)%
Financial ($000, except per share)                                          
Revenue                                    120,310        114,263        5% 
Royalties                                    9,205          9,870       (7)%
Funds from operations                       90,078         80,410       12% 
Funds from operations per share               0.62           0.60        3% 
Total dividends                             26,178         24,245        8% 
Total dividends per share                     0.18           0.18        -  
Payout ratio (%)                                28             30       (7)%
Earnings                                    25,823         26,036       (1)%
Earnings per share                            0.18           0.19       (5)%
Capital expenditures                       156,847         94,688       66% 
Weighted average shares outstanding    145,449,651    133,913,301        9% 
As at December 31                                                           
Net debt (before future                                                     
 compensation expense and                                                   
 unrealized hedging gains)                                                  
Sha
reholders' equity                                                        
Total assets                                                                
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                                      12 Months Ended December 31        %  
                                              2012           2011   Change  
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Operations                                                                  
Production                                                                  
 Natural gas (mcf/d)                       238,490        189,653       26% 
 Oil & NGLs (bbl/d)                          4,778          3,856       24% 
 Thousand cubic feet equivalent                                             
  (mcfe/d @ 1:6)                           267,160        212,789       26% 
 Barrels of oil equivalent (boe/d @                                         
  6:1)                                      44,527         35,465       26% 
Product prices                                                              
 Natural gas ($/mcf)                          3.23           4.47      (28)%
 Oil & NGLs ($/bbl)                          73.92          81.67       (9)%
 Operating expenses ($/mcfe)                  0.32           0.35       (9)%
 Transportation ($/mcfe)                      0.12           0.13       (8)%
 Field netback ($/mcfe)                       3.46           4.46      (22)%
 General & administrative expenses                                          
  ($/mcfe)                                    0.04           0.06      (33)%
 Interest expense ($/mcfe)                    0.13           0.28      (54)%
Financial ($000, except per share)                                          
Revenue                                    411,400        424,560       (3)%
Royalties                                   30,754         41,064      (25)%
Funds from operations                      308,865        314,622       (2)%
Funds from operations per share               2.19           2.36       (7)%
Total dividends                            101,593         96,068        6% 
Total dividends per share                     0.72           0.72        -  
Payout ratio (%)                                33             31        6% 
Earnings                                    93,951        128,183      (27)%
Earnings per share                            0.67           0.96      (30)%
Capital expenditures                       617,985        379,061       63% 
Weighted average shares outstanding    141,093,829    133,196,301        6% 
As at December 31                                                           
Net debt (before future                                                     
 compensation expense and                                                   
 unrealized hedging gains)                 662,461        465,391       42% 
Shareholders' equity                     1,210,067      1,015,708       19% 
Total assets                             2,203,524      1,800,252       22% 
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                                     3 Months Ended         12 Months Ended 
                                        December 31             December 31 
($000)                             2012        2011        2012        2011 
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Cash flows from operating                                                   
 activities                      78,878      85,592     284,309     289,995 
Change in non-cash working                                                  
 capital                          4,457     (19,139)     12,920       3,085 
Change in provision for                                                     
 performance based                                                          
 compensation                    (7,712)     (8,739)     (2,819)     (1,154)
Income tax paid on account                                                  
 of 2003 reassessment             1,868           -       1,868           - 
Performance based                                                           
 compensation                    12,587      22,696      12,587      22,696 
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Funds from operations            90,078      80,410     308,865     314,622 
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Funds from operations per                                                   
 share                             0.62        0.60        2.19        2.36 
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(1) Funds from operations - Management uses funds from operations to analyze
    the operating performance of its energy assets. In order to facilitate  
    comparative analysis, funds from operations is defined throughout this  
    report as earnings before performance based compensation, non-cash and  
    non-recurring expenses. Management believes that funds from operations  
    is an important parameter to measure the value of an asset when combined
    with reserve life. Funds from operations is not a measure recognized by 
    Canadian generally accepted accounting principles ("GAAP") and does not 
    have a standardized meaning prescribed by GAAP. Therefore, funds from   
    operations, as defined by Peyto, may not be comparable to similar       
    measures presented by other issuers, and investors are cautioned that   
    funds from operations should not be construed as an alternative to net  
    earnings, cash flow from operating activities or other measures of      
    financial performance calculated in accordance with GAAP. Funds from    
    operations cannot be assured and future dividends may vary.             

 
The Peyto Strategy 
The Peyto strategy has long been one of building enduring shareholder
value by focusing on generating the maximum possible returns on
invested capital. This disciplined model has been tested during times
of high commodity prices and record industry activity levels as well
as low commodity prices and low activity levels. As with any
commodity business, a focus on keeping costs low at all times yields
significant advantages over the competition and contributes to
generating the best return on the capital invested. Peyto has
successfully executed this strategy, aggressively investing capital
during opportunistic periods in the cycle while at other times
restricting investment, but at all times focusing on cost control. In
total, over $2.9 billion has been invested in developing producing
reserves that to date have sold for over 1.75 times the total average
cost to develop and produce them. The following table illustrates the
profitability of the Peyto strategy with the average sales price far
exceeding Peyto's historic costs of development and production. 


 
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($/Mcfe)                      2002    2003    2004    2005    2006    2007  
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Sales Price                   $4.78   $7.21   $7.32   $8.87   $8.76   $8.93 
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Cost to develop(1)           ($0.84) ($1.33) ($1.60) ($2.39) ($2.95) ($2.11)
Cost to produce(2)           ($1.59) ($2.16) ($2.21) ($2.76) ($2.66) ($2.75)
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"Profit"                      $2.35   $3.72   $3.51   $3.72   $3.15   $4.07 
Payout                                $1.36   $2.28   $2.81   $3.47   $3.92 
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($/Mcfe)                              2008    2009    2010    2011    2012  
----------------------------------------------------------------------------
Sales Price                           $9.54   $6.75   $6.15   $5.47   $4.21 
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Cost to develop(1)                   ($2.88) ($2.26) ($2.10) ($2.12) ($2.22)
Cost to produce(2)                   ($3.01) ($1.75) ($1.63) ($1.35) ($1.05)
----------------------------------------------------------------------------
"Profit"                              $3.65   $2.74   $2.42   $2.00   $0.94 
Payout                                $4.25   $4.03   $3.37   $1.24   $1.04 
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1. Cost to develop is the PDP FD&A  
2. Cost to produce is the total cash costs including Royalties,
Operating costs, Transportation, G&A and Interest.  
3. Payout is the annual distribution or dividend in $/mcfe of
production.  
In total, over $1.3 billion in profit has been returned to
shareholders. As illustrated above, these payments have come from the
ongoing profitable development and production of reserves. The
success and sustainability of the Peyto strategy continues to be
evident.  
Capital Expenditures 
Peyto deployed a record amount of capital in 2012, with an
exploration and development program comprising $452 million and a
corporate acquisition costing $166 million, after associated
dispositions.  
The 2012 exploration and development program was 19% larger than the
2011 program making it the largest in the Company's 14 year history.
In total, $338 million was invested into the drilling and completion
of 86 gross (76 net) horizontal wells, while $47 million was invested
into pipelines and wellsite equipment to bring those wells on
production. An additional $11 million was invested into expanding
Peyto's natural gas processing capacity while $26 million was
invested in the Oldman plant enhanced liquids extraction facility.  
Peyto spent $29 million adding to its extensive inventory of
profitable, high quality drilling locations with a minor property
acquisition in the Sundance area and the successful purchase of 72
new sections of crown land at an average price of $232/acre. 
On August 14, 2012, Peyto closed the acquisition of Open Range for an
effective total capital cost of $187.2 million. The acquisition was
conducted pursuant to a plan of arrangement with Peyto exchanging
0.0723 Peyto shares for each Open Range share (5.4 million Peyto
shares total) and assuming $75 million in net debt (inclusive of
transaction costs). On December 1, 2012, Peyto disposed of some minor
non-core Open Range assets in the Waskahigan area for total proceeds
of $20.9 million, which effectively reduced the cost of the
acquisition to $166.3 million. 
The following table summarizes the increased capital expenditures for
the fourth quarter and 2012 year. 


 
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                                 Three Months ended     Twelve Months ended 
                                            Dec. 31                 Dec. 31 
($000)                             2012        2011        2012        2011 
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Land                              5,206       5,910      10,770      21,002 
Seismic                             612       1,245       1,741       2,859 
Drilling - Exploratory &                                                    
 Development                    123,778      77,570     337,988     279,446 
Production Equipment,                                                       
 Facilities & Pipelines          48,015      10,644      84,482      72,079 
Acquisition of Open Range                                                   
 Energy Corp.                         -           -     187,187           - 
Property Acquisitions                75         527      17,841       5,581 
Dispositions                    (16,969)     (1,208)    (17,646)     (1,906)
(Gains) Losses on                                                           
 Dispositions                    (3,870)     (1,126)     (4,378)     (1,634)
----------------------------------------------------------------------------
Total Capital Expenditures      156,847      93,562     617,985     377,427 
----------------------------------------------------------------------------

 
Reserves 
Peyto was successful growing reserves and values in all categories in
2012. The following table illustrates the change in reserve volumes
and Net Present Value ("NPV") of future cash flows, discounted at 5%,
before income tax and using forecast pricing. 


 
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                                                                  % Change, 
                                                                       debt 
                                 As at December 31                 adjusted 
                                         2012 2011   % Change   per share(1)
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Reserves (BCFe)                                                             
Proved Producing                   945         765         24%           10%
Total Proved                     1,659       1,352         23%            9%
Proved + Probable                                                           
 Additional                      2,353       1,935         22%            8%
                                                                            
Net Present Value                                                           
 ($millions) Discounted at                                                  
 5%                                                                         
Proved Producing                $2,806      $2,624          7%           -8%
Total Proved                    $4,166      $3,972          5%           -7%
Proved + Probable                                                           
 Additional                     $5,732      $5,484          5%           -6%
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(1)   Per share reserves are adjusted for changes in net debt by converting 
      debt to equity using the Dec 31 share price of $22.99 for 2012 and    
      share price of $24.39 for 2011. Net Present Values are adjusted for   
      debt by subtracting net debt from the value prior to calculating per  
      share amounts.                                                        
Note: based on the InSite Petroleum Consultants ("InSite") report effective 
      December 31, 2012. The InSite price forecast is available at          
      http://www.insitepc.com/. For more information on Peyto's reserves,   
      refer to the Press Releases dated February 13, 2013 and February 14,  
      2013 announcing the 2012 Year End Reserve Report which is available on
      the website at http://www.peyto.com/. The complete statement of       
      reserves data and required reporting in compliance with NI 51-101 will
      be included in Peyto's Annual Information Form to be released in March
      2013.                                                                 

 
Performance Ratios  
The following table highlights additional annual performance
indicators, to be used for comparative purposes, but it is cautioned
that in isolation they do not measure investment success. 


 
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                               2012    2011    2010    2009    2008    2007 
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Proved Producing                                                            
  FD&A ($/mcfe)               $2.22   $2.12   $2.10   $2.26   $2.88   $2.11 
  RLI (yrs)                       9       9      11      14      14      13 
  Recycle Ratio                 1.6     1.9     2.0     1.8     2.3     2.8 
  Reserve Replacement           284%    230%    239%     79%    110%    127%
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Total Proved                                                                
  FD&A ($/mcfe)               $2.04   $2.13   $2.35   $1.73   $3.17   $1.57 
  RLI (yrs)                      15      16      17      21      17      16 
  Recycle Ratio                 1.7     1.9     1.8     2.3     2.1     3.7 
  Reserve Replacement           414%    452%    456%    422%    139%    175%
  Future Development Capital                                                
   ($MM)                     $1,318  $1,111    $741    $446    $222    $169 
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Proved plus Probable                                                        
 Additional                                                                 
  FD&A ($/mcfe)               $1.68   $1.90   $2.19   $1.47   $3.88   $1.56 
  RLI (yrs)                      22      22      25      29      23      21 
  Recycle Ratio                 2.1     2.1     1.9     2.8     1.7     3.7 
  Reserve Replacement           527%    585%    790%    597%    122%    117%
  Future Development Capital                                                
   ($MM)                     $2,041  $1,794  $1,310    $672    $390    $321 
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--  FD&A (finding, development and acquisition) costs are used as a measure
    of capital efficiency and are calculated by dividing the capital costs
    for the period, including the change in undiscounted future development
    capital ("FDC"), by the change in the reserves, incorporating revisions
    and production, for the same period (eg. Total Proved
    ($618+$207)/(1,659-1,352+98) = $2.04/mcfe or $12.24/boe). 
--  The reserve life index (RLI) is calculated by dividing the reserves (in
    boes) in each category by the annualized average production rate in
    boe/year (eg. Proved Producing 157,491/(49.754x365) = 8.7). Peyto
    believes that the most accurate way to evaluate the current reserve life
    is by dividing the proved developed producing reserves by the actual
    fourth quarter average production. In Peyto's opinion, for comparative
    purposes, the proved developed producing reserve life provides the best
    measure of sustainability. 
--  The Recycle Ratio is calculated by dividing the field netback per MCFe,
    before hedging, by the FD&A costs for the period (eg. Proved Producing
    (($3.46)/$2.22=1.6). The recycle ratio is comparing the netback from
    existing reserves to the cost of finding new reserves and may not
    accurately indicate investment success unless the replacement reserves
    are of equivalent quality as the produced reserves. 
--  The reserve replacement ratio is determined by dividing the yearly
    change in reserves before production by the actual annual production for
    the year (eg. Total Proved ((1,659-1,352+98)/98) = 4.14). 

 
Value Creation/Reconciliation  
In order to measure the success of all of the capital invested in
2012, it is necessary to quantify the total amount of value added
during the year and compare that to the total amount of capital
invested. As requested, Insite has run last year's reserve evaluation
with this year's price forecast to remove the change in value
attributable to both commodity prices and changing royalties. This
approach isolates the value created by the Peyto team from the value
created (or lost) by those changes outside of their control. Since
the capital investments in 2012 were funded from a combination of
cash flow, debt and equity, it is necessary to include the change in
debt and the change in shares outstanding to determine if the change
in value is truly accretive to shareholders. 
At year end 2012, Peyto's estimated net debt had increased by $196.8
million to $662.4 million while the number of shares outstanding had
increased by 10.3 million shares to 148.7 million shares. The change
in debt includes all of the capital expenditures, as well as
acquisitions, and the total fixed and performance based compensation
paid out during the year.  
Based on this reconciliation of changes in BT NPV, the Peyto team was
able to create $963 million of Proved Producing, $1.36 billion of
Total Proved, and $2.0 billion of Proved plus Probable Additional
undiscounted reserve value, with a $618 million capital investment.
The ratio of value creation to capital expenditure is what Peyto
refers to as the NPV recycle ratio, which is simply the undiscounted
value addition, resulting from the capital program, divided by the
capital investment. For 2012, the Proved Producing NPV recycle ratio
is 1.6. Refer to the value reconciliation table in the February 14,
2013 Reserve Press Release for additional details on the value
creation determination.  
Performance Measures  
There are a number of performance measures that are used in the oil
and gas industry in an attempt to evaluate how profitably capital has
been invested. Peyto believes that the value analysis and
reconciliation presented above is the best determination of
profitability as it compares the value of what was created relative
to what was invested. This is because the NPV of an oil and gas asset
takes into consideration the reserves, the production forecast, the
future royalties and operating costs, future capital and the current
commodity price outlook. In 2012, the Proved Producing NPV recycle
ratio was 1.6 times. This means for each dollar invested, the Peyto
team was able to create 1.6 new dollars of Proved Producing reserve
value. The average NPV Recycle Ratio over the last 5 years is 3.0
times for undiscounted future values or 2.2 times for future values
discounted at 10%. The historic NPV recycle ratios are presented in
the following table. 


 
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Value Creation       Dec 31, Dec 31, Dec 31, Dec 31, Dec 31, Dec 31, Dec 31,
                        2012    2011    2010    2009    2008    2007    2006
----------------------------------------------------------------------------
NPV0 Recycle Ratio                                                          
 Proved Producing        1.6     2.4     3.5     5.4     2.1     4.7     2.9
 Total Proved            2.2     4.7     6.1    18.9     2.5     5.5     2.9
 Proved + Probable                                                          
  Additional             3.2     6.6    10.3    27.1     2.2     3.8     3.8
----------------------------------------------------------------------------
 
--  NPV0 (net present value) recycle ratio is calculated by dividing the
    undiscounted NPV of reserves added in the year by the total capital cost
    for the period (eg. Proved Producing ($963/$618) = 1.6). 

 
Quarterly Review  
Activity in the fourth quarter of 2012 included the drilling of 28
gross (27.2 net) horizontal wells, the completion of 33 gross (29.6
net) wells and the installation of wellsite equipment and tie in of
34 gross (30.4 net) wells. Capital expenditures in Q4 totaled $156.8
million with $78 million spent on drilling, $47 million on
completions, and $22 million on wellsite equipment and pipelines.
Installation of the enhanced liquids extraction facilities at the
Oldman gas plant was responsible for the majority of the $25 million
invested in facilities. In the quarter, 30.5 sections of new land was
purchased at crown land sales for $5.2 million or $267/ac. 
On December 1, 2012 Peyto disposed of some minor non-core Open Range
assets in the Waskahigan area for total proceeds of $20.9 million
reflected in the previous capital summary as a disposition and gain
on disposition. 
Production for Q4 2012 was up 26% from Q4 2011 to 49,754 boe/d
including 299 mmcf/d of natural gas and 5,286 bbl/d of oil and
natural gas liquids. Fourth quarter production was less than
expected, however, due to an unanticipated outage at Peyto's Oldman
gas processing facility. The cause of the outage was a faulty piece
of equipment installed during the new Oldman Deep Cut plant
expansion. The defective equipment prevented the operation of
approximately two thirds, or 80 mmcf/d, of the processing capacity at
the facility. This equipment has been repaired and the impacted
processing capacity was brought back online on January 7, 2013 with
the Deep Cut plant operation commencing January 25, 2013.
Approximately 10,700 boe/d of net production was offline for the
final 13 days in December. 
Peyto's natural gas price in the fourth quarter 2012 of $3.45/mcf was
18% lower than the previous year, while the realized oil and natural
gas liquids price of $73.01/bbl was 17% lower. These prices combined
for a realized price of $4.38/mcfe including $0.13/mcfe of realized
hedging gain. Q4 2012 total cash costs of $1.10/mcfe included
$0.34/mcfe for royalties, $0.31/mcfe for operating costs, $0.11/mcfe
for transportation, $0.02/mcfe for G&A and $0.32/mcfe for interest.
Realized prices less cash costs resulted in cash netbacks for the
quarter of $3.28/mcfe or a 75% operating margin. 
Peyto incurred a one-time tax charge of $1.9 million or $0.12/mcfe in
the quarter due to the reassessment of Peyto's 2003 Alberta income
tax return. The reassessment related to the treatment of the payout
of stock options for income tax purposes upon conversion to an income
trust in 2003. The federal reassessment was paid to Canada Revenue
Agency in 2008, however, the Alberta Government subsequently
reassessed the 2003 Alberta income tax return in January, 2013 which
was paid in the same month and accrued as a one-time charge in the
2012 financial results. 
Marketing  
The current natural gas price outlook is substantially better than
this time last year. Although storage volumes are at the high end of
historical levels, growing demand and flat to declining North
American natural gas supply is supporting prices at $3.00/GJ CND$ and
$3.50/MMBTU US$. With current supplies matching demand, weather
should continue to play a significant role in future prices. In
addition, natural gas is playing an increasing role for summer power
generation, particularly in light of the current projections for
decreased hydro power this coming spring and ongoing retirement of
coal fired power plants. 
Natural gas liquids prices have, in general, remained substantially
higher than the equivalent price in gaseous form. Recent industry
trends to extract more Propane and Ethane from the natural gas
production have increase supplies and filled available liquefied
petroleum gas ("LPG") fractionation plant capacity. This has put
significant downward pressure on the price for these specific
products which will likely continue for the near future. The majority
of Peyto's LPG is under long term contract for transportation and
fractionation.  
Approximately 50% of Peyto's natural gas production in the fourth
quarter had been pre-sold in forward sales done over the previous
year at an average price of $3.17/GJ. The remaining balance of
production was subject to AECO monthly spot prices that averaged
$2.90/GJ. On a blended basis, Peyto's realized gas price was $3.04/GJ
or $3.45/mcf, reflective of Peyto's high heat content natural gas
production.  
The Company's hedging practice of layering in future sales in the
form of fixed price swaps, in order to smooth out the volatility in
natural gas price, continued throughout the quarter and into 2013.
The following table summarizes the remaining hedged volumes and
prices for the upcoming years, effective March 6, 2013: 


 
----------------------------------------------------------------------------
                         Future Sales               Average Price (CAD)     
----------------------------------------------------------------------------
                       GJ            Mcf            $/GJ          $/Mcf     
----------------------------------------------------------------------------
      2013         54,842,500     46,873,932       $3.20          $3.74     
      2014         27,575,000     23,568,376       $3.24          $3.79     
----------------------------------------------------------------------------
      Total        82,417,500     70,442,308       $3.21          $3.76     
----------------------------------------------------------------------------

 
As illustrated in the following table, Peyto's annual realized
natural gas liquids prices(1) were approximately 10% lower on a year
over year basis, due primarily to realized Propane prices which were
45% lower than the price realized in 2011. 


 
----------------------------------------------------------------------------
                            Three Months ended           Twelve Months ended
                                       Dec. 31                       Dec. 31
                           2012           2011           2012           2011
----------------------------------------------------------------------------
Condensate                                                                  
 ($/bbl)                  91.22         101.08          94.78          94.47
Propane ($/bbl)           25.58          46.03          24.12          44.00
Butane ($/bbl)            63.38          67.46          64.05          63.41
Pentane ($/bbl)           94.34         104.03          98.93          96.63
----------------------------------------------------------------------------
 

 
(1) Liquids prices are Peyto realized prices in Canadian dollars adjusted   
    for fractionation and transportation.                                   

 
Peyto's hedging practice with respect to propane and butane also
continued throughout the fourth quarter. The following table
summarizes the hedged volumes and prices for the upcoming years,
effective March 6, 2013. 


 
----------------------------------------------------------------------------
                            Propane                       Butane            
----------------------------------------------------------------------------
                  Future Sales  Average Price   Future Sales  Average Price 
                     (bbls)       ($USD/bbl)       (bbls)       ($USD/bbl)  
----------------------------------------------------------------------------
2013                213,972         $33.95         15,345         $65.88    
----------------------------------------------------------------------------

 
Activity Update 
Peyto has continued its record level of activity into the first
quarter of 2013. Nine rigs are drilling and four completions crews
are following behind the drilling rigs. To the end of February, 17
gross (16.9 net) wells have been rig released and 14 gross (13.2 net)
wells have been brought on production. 
Current production is approximately 57,000 boe/d which includes 4,300
boe/d of new additions since early January. Over 5,000 boe/d of
production awaits tie-in of 8.0 net wells that have been completed
but are not yet onstream. 
Over the first two months of 2013, two compressor expansion projects
were completed. An additional 10 MMcf/d of compression was added to
the Nosehill Plant taking the facility capacity to 120 MMcf/d. In
addition, another 10 MMcf/d of compression was added to the Wildhay
Plant taking it to a capacity of 70 MMcf/d. 
Three plant construction projects are in the early stage of equipment
fabrication with field work anticipated for the summer of 2013 and
start-ups ranging from late summer to fall. The first project is a 30
MMcf/d addition to the Swanson Plant (taking it to 60 MMcf/d) for the
accommodation of Ansell area growth volumes. In addition to the plant
expansion, a 50 km strategic pipeline from Ansell to Swanson is
currently under construction with targeted completion after breakup.
The second project is a new Oldman North Plant to be located adjacent
to the existing 125 MMcf/d Oldman Plant and initially designed for 40
MMcf/d. This plant will handle ongoing Cardium and Falher horizontal
well development. A third new facility is planned for mid-fall for a
new step-out area of Wilrich development that is presently undergoing
early stage delineation drilling. 
The Oldman Deep Cut facility built at the end of 2012 was
successfully brought online in mid-January. The plant is currently
running just below its 80 MMcfd raw gas capacity as some final
re-compression tuning occurs for the four new compressors. The
overall Oldman LPG recovery level has increased from a pre-Deep Cut
level of 1,600 bbl/d to a present level of 2,400 bbl/d at the current
-75 degrees C operating level for the Deep Cut train. With continued
tuning of the re-compression, throughput will be brought up and
chilling will be dropped towards the -80 degrees C design level to
realize the full 2,600 bbl/d of LPG. 
As in most past years, Peyto tentatively plans to shut down its
drilling operations over spring break-up which is contemplated to
occur from early April to mid-May and resume its drilling program
with nine rigs. Post break-up drilling will focus in the traditional
Greater Sundance area with volumes filling the new Oldman North
Plant, the Ansell area with volumes pipelined to the expanded Swanson
Plant, and with some additional Northern Cardium drilling. The $450
to $500 million capital program is on pace and it is expected that
target 2013 exit production levels of 62,000 to 67,000 boe/d will be
reached. 
2013 Outlook  
2013 is forecast to be the most active in the Company's history. It
also comes at a time when the majority of natural gas producers in
North America are challenged by low natural gas prices and high
costs, rendering many plays uneconomic. Over its history, Peyto has
maintained a unique low cost advantage that allows the Company to
profitably grow its asset base, despite lower commodity prices,
taking advantage of lower service and material costs. In effect,
Peyto can be "greedy when others are fearful" and capture new
opportunities when others are cutting capital budgets and
rationalizing assets. This prevailing economic condition is forecast
to continue throughout 2013 allowing Peyto the opportunity to deliver
the same superior total returns to shareholders as in the past.
Peyto's expertise in the Alberta Deep Basin will serve it well in
this regard. The company's financial flexibility, quality asset base
and strong balance sheet position Peyto to continue to be
opportunistic. As always, capital investments will only be pursued if
Peyto's high return objectives can be met.  
Conference Call and Webcast  
A conference call will be held with the senior management of Peyto to
answer questions with respect to the 2012 fourth quarter and full
year financial results on Thursday, March 7th, 2013, at 9:00 a.m.
Mountain Standard Time (MST), or 11:00 a.m. Eastern Standard Time
(EST). To participate, please call 1-416-340-8530 (Toronto area) or
1-877-440-9795 for all other participants. The conference call will
also be available on replay by calling 1-905-694-9451 (Toronto area)
or 1-800-408-3053 for all other parties, using passcode 9284446. The
replay will be available at 11:00 a.m. MST, 1:00 p.m. EST Thursday,
March 7th, 2013 until midnight EDT on Thursday, March 14th, 2013. The
conference call can also be accessed through the internet at
http://events.digitalmedia.telus.com/peyto/030713/index.php. After
this time the conference call will be archived on the Peyto
Exploration & Development website at www.peyto.com . 
Management's Discussion and Analysis  
A copy of the fourth quarter report to shareholders, including the
MD&A, and audited financial statements and related notes is available
at http://www.peyto.com/news/Q42012MDandA.pdf and will be filed at
SEDAR, www.sedar.com, at a later date. 
Annual General Meeting  
Peyto's Annual General Meeting of Shareholders is scheduled for 3:00
p.m. on Wednesday, June 5, 2013 at Livingston Place Conference
Centre, +15 level, 222-3rd Avenue SW, Calgary, Alberta. Shareholders
are encouraged to visit the Peyto website at www.peyto.com where
there is a wealth of information designed to inform and educate
investors. A monthly President's Report can also be found on the
website which follows the progress of the capital program and the
ensuing production growth, along with video and audio commentary from
Peyto's senior management.  
Darren Gee, President and CEO  
March 6, 2013 
Certain information set forth in this document and Management's
Discussion and Analysis, including management's assessment of Peyto's
future plans and operations, contains forward-looking statements. In
particular, but without limiting the foregoing, this news release
contains forward-looking information and statements pertaining to the
following: the timing of its enhanced liquids extraction project and
guidance as to the capital expenditure plans of Peyto under the
heading "2013 Outlook". By their nature, forward-looking statements
are subject to numerous risks and uncertainties, some of which are
beyond these parties' control, including the impact of general
economic conditions, industry conditions, volatility of commodity
prices, currency fluctuations, imprecision of reserve estimates,
environmental risks, competition from other industry participants,
the lack of availability of qualified personnel or management, stock
market volatility and ability to access sufficient capital from
internal and external sources. Readers are cautioned that the
assumptions used in the preparation of such information, although
considered reasonable at the time of preparation, may prove to be
imprecise and, as such, undue reliance should not be placed on
forward-looking statements. Peyto's actual results, performance or
achievement could differ materially from those expressed in, or
implied by, these forward-looking statements and, accordingly, no
assurance can be given that any of the events anticipated by the
forward-looking statements will transpire or occur, or if any of them
do so, what benefits Peyto will derive therefrom.  


 
Peyto Exploration & Development Corp.                                       
Consolidated Balance Sheet                                                  
(Amount in $thousands)                                                      
                                                  December 31    December 31
                                                         2012           2011
----------------------------------------------------------------------------
Assets                                                                      
Current assets                                                              
Cash                                                        -         57,224
Accounts receivable                                    85,677         53,829
Due from private placement (Note 7)                     3,459          9,740
Derivative financial instruments (Note 13)             10,254         38,530
Prepaid expenses                                        4,150          3,991
----------------------------------------------------------------------------
                                                      103,540        163,314
----------------------------------------------------------------------------
                                                                            
Long-term derivative financial instruments                                  
 (Note 13)                                                  -          6,304
Prepaid capital                                         3,714          1,414
Property, plant and equipment, net (Note 4)         2,096,270      1,629,220
----------------------------------------------------------------------------
                                                    2,099,984      1,636,938
----------------------------------------------------------------------------
                                                                            
----------------------------------------------------------------------------
                                                    2,203,524      1,800,252
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Liabilities                                                                 
Current liabilities                                                         
Accounts payable and accrued liabilities              164,946        110,483
Current income tax                                      1,890              -
Dividends payable (Note 7)                              8,911          8,278
Provision for future performance based                                      
 compensation (Note 11)                                 2,677          4,321
----------------------------------------------------------------------------
                                                      178,424        123,082
----------------------------------------------------------------------------
                                                                            
Long-term debt (Note 5)                               580,000        470,000
Long-term derivative financial instruments                                  
 (Note 13)                                              2,532              -
Provision for future performance based                                      
 compensation (Note 11)                                    59          1,235
Decommissioning provision (Note 6)                     58,201         38,037
Deferred income taxes (Note 12)                       174,241        152,190
----------------------------------------------------------------------------
                                                      815,033        661,462
----------------------------------------------------------------------------
                                                                            
Shareholders' equity                                                        
Shareholders' capital (Note 7)                      1,124,382        889,115
Shares to be issued (Note 7)                            3,459          9,740
                                                                            
Retained earnings                                      75,247         82,889
Accumulated other comprehensive income (Note                                
 7)                                                     6,979         33,964
----------------------------------------------------------------------------
                                                    1,210,067      1,015,708
----------------------------------------------------------------------------
                                                    2,203,524      1,800,252
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Approved by the Board of Directors                           
                                                             
(signed) "Michael MacBean"              (signed) "Darren Gee"
Director                                Director             
                                                             
Peyto Exploration & Development Corp.                                       
Consolidated Income Statement                                               
(Amount in $thousands)                                                      
                                                                            
                                                     Year ended December 31 
                                                        2012           2011 
----------------------------------------------------------------------------
Revenue                                                                     
Oil and gas sales                                    357,734        387,240 
Realized gain on hedges (Note 13)                     53,667         37,320 
Royalties                                            (30,754)       (41,064)
----------------------------------------------------------------------------
Petroleum and natural gas sales, net                 380,647        383,496 
----------------------------------------------------------------------------
                                                                            
Expenses                                                                    
Operating (Note 8)                                    31,260         27,379 
Transportation                                        11,275          9,754 
General and administrative (Note 9)                    3,846          4,911 
Market and reserves based bonus (Note 11)             12,587         22,696 
Future performance based compensation (Note           (2,819)        (1,154)
 11)                                                                        
Interest (Note 10)                                    25,401         21,881 
Accretion of decommissioning provision (Note           1,044            840 
 10)                                                                        
Depletion and depreciation (Note 4)                  172,338        130,678 
Gain on disposition of assets (Note 4)                (4,378)        (1,634)
----------------------------------------------------------------------------
                                                     250,554        215,351 
----------------------------------------------------------------------------
Earnings before taxes                                130,093        168,145 
----------------------------------------------------------------------------
                                                                            
Income tax                                                                  
Deferred income tax expense (recovery) (Note          34,274         35,013 
 12)                                                                        
Income tax expense (Note 12)                           1,868          4,949 
                                                                            
----------------------------------------------------------------------------
Earnings for the year                                 93,951        128,183 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
                                                                            
----------------------------------------------------------------------------
Earnings per share (Note 7)                                                 
Basic and diluted                                     $ 0.67         $ 0.96 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
----------------------------------------------------------------------------
Weighted average number of common shares                                    
 outstanding (Note 7)                                                       
Basic and diluted                                141,093,829    133,196,103 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
                                                                            
Peyto Exploration & Development Corp.                                       
Consolidated Statement of Comprehensive Income                              
(Amount in $thousands)                                                      
                                                                            
                                                                            
                                                     Year ended December 31 
                                                        2012           2011 
----------------------------------------------------------------------------
Earnings for the year                                 93,951        128,183 
Other comprehensive income                                                  
Change in unrealized gain (loss) on cash flow                               
 hedges                                               17,687         54,243 
Deferred tax recovery (expense)                        8,995         (3,852)
Realized gain on cash flow hedges                    (53,667)       (37,320)
----------------------------------------------------------------------------
Comprehensive Income                                  66,966        141,254 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Peyto Exploration & Development Corp.                                       
Consolidated Statement of Changes in Equity                                 
(Amount in $thousands)                                                      
                                                                            
                                                                            
                                                     Year ended December 31 
                                                        2012           2011 
----------------------------------------------------------------------------
Shareholders' capital, Beginning of Year             889,115        755,831 
----------------------------------------------------------------------------
Common shares issued                                 115,024        115,126 
Common shares issued pursuant to acquisition                                
 of Open Range Energy Corp.                          112,187              - 
Common shares issued by private placement             11,952         17,150 
Common shares issuance costs (net of tax)             (3,896)        (3,854)
Common shares issued pursuant to DRIP                      -          1,973 
Common shares issued pursuant to OTUPP                     -          2,889 
----------------------------------------------------------------------------
Shareholders' capital, End of Year                 1,124,382        889,115 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
                                                                            
                                                                            
----------------------------------------------------------------------------
Common shares to be issued, Beginning of Year          9,740         17,285 
----------------------------------------------------------------------------
Common shares issued                                  (9,740)       (17,285)
Common shares to be issued                             3,459          9,740 
----------------------------------------------------------------------------
Common shares to be issued, End of Year                3,459          9,740 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
                                                                            
                                                                            
----------------------------------------------------------------------------
Retained earnings, Beginning of Year                  82,889         50,774 
----------------------------------------------------------------------------
Earnings for the year                                 93,951        128,183 
Dividends (Note 7)                                  (101,593)       (96,068)
----------------------------------------------------------------------------
Retained earnings, End of Year                        75,247         82,889 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
                                                                            
                                                                            
----------------------------------------------------------------------------
Accumulated other comprehensive income,                                     
 Beginning of Year                                    33,964         20,893 
----------------------------------------------------------------------------
Other comprehensive income (loss)                    (26,985)        13,071 
----------------------------------------------------------------------------
Accumulated other comprehensive income, End of                              
 Year                                                  6,979         33,964 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
                                                                            
                                                                            
----------------------------------------------------------------------------
Total Shareholders' Equity                         1,210,067      1,015,708 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Peyto Exploration & Development Corp.                                       
Consolidated Statement of Cash Flows                                        
(Amount in $thousands)                                                      
                                                                            
                                                                            
                                                     Year ended December 31 
                                                        2012           2011 
----------------------------------------------------------------------------
Cash provided by (used in)                                                  
Operating activities                                                        
Earnings                                              93,951        128,183 
Items not requiring cash:                                                   
  Deferred income tax                                 34,274         35,013 
  Gain on disposition of assets                       (4,378)        (1,634)
  Depletion and depreciation                         172,338        130,678 
  Accretion of decommissioning provision               1,044            840 
Change in non-cash working capital related to                               
 operating activities                                (12,920)        (3,085)
----------------------------------------------------------------------------
                                                     284,309        289,995 
----------------------------------------------------------------------------
Financing activities                                                        
Issuance of common shares                            126,976        132,276 
Issuance costs                                        (5,195)        (5,137)
Dividends                                           (100,960)      (103,615)
Increase (decrease) in bank debt                     (40,000)       115,000 
Repayment of Open Range bank debt                    (72,000)             - 
Issuance of long term notes                          150,000              - 
----------------------------------------------------------------------------
                                                      58,821        138,524 
----------------------------------------------------------------------------
Investing activities                                                        
Additions to property, plant and equipment          (400,354)      (382,189)
Dispositions of property, plant and equipment              -          3,000 
----------------------------------------------------------------------------
                                                    (400,354)      (379,189)
----------------------------------------------------------------------------
                                                                            
----------------------------------------------------------------------------
Net increase in cash                                 (57,224)        49,330 
Cash, beginning of year                               57,224          7,894 
----------------------------------------------------------------------------
Cash, end of year                                          -         57,224 
----------------------------------------------------------------------------
                                                                            
The following amounts are included in Cash flows from operating activities: 
----------------------------------------------------------------------------
                                                                            
Cash interest paid                                       23,460       19,656
Cash taxes paid                                               -            -
----------------------------------------------------------------------------

 
Peyto Exploration & Development Corp. 
Notes to Consolidated Financial Statements 
As at December 31, 2012 and 2011  
(Amount in $ thousands, except as otherwise noted) 
1.Nature of operations 
Peyto Exploration & Development Corp. and its wholly owned subsidiary
Open Range Energy Corp. ("Open Range"), (collectively "Peyto" or the
"Company") are Calgary based oil and natural gas companies. Peyto and
Open Range amalgamated on January 1, 2013. Peyto conducts
exploration, development and production activities in Canada. Peyto
is incorporated and domiciled in the Province of Alberta, Canada. The
address of its registered office is 1500, 250 - 2nd Street SW,
Calgary, Alberta, Canada, T2P 0C1. 
These financial statements were approved and authorized for issuance
by the Board of Directors of Peyto on March 5, 2013. 
2.Basis of presentation 
These consolidated financial statements ("financial statements") for
the years ended December 31, 2012 and December 31, 2011 represent the
Company's results and financial position in accordance with
International Financial Reporting Standards ("IFRS"). The
consolidated financial statements include the accounts of Peyto
Exploration & Development Corp. and its subsidiary. Subsidiaries are
defined as any entities, including unincorporated entities such as
partnerships, for which the Company has the power to govern their
financial and operating policies to obtain benefits from their
activities. Intercompany balances, net earnings and unrealized gains
and losses arising from intercompany transactions are eliminated in
preparing the consolidated financial statements. 
a)Summary of significant accounting policies 
The precise determination of many assets and liabilities is dependent
upon future events and the preparation of periodic financial
statements necessarily involves the use of estimates and
approximations. Accordingly, actual results could differ from those
estimates. The financial statements have, in management's opinion,
been properly prepared within reasonable limits of materiality and
within the framework of the Company's basis of presentation as
disclosed.  
b) Significant accounting estimates and judgements 
The timely preparation of the financial statements in conformity with
IFRS requires that management make estimates and assumptions and use
judgment regarding the reported amounts of assets and liabilities and
disclosures of contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues and
expenses during the period. Such estimates primarily relate to
unsettled transactions and events as of the date of the financial
statements. Accordingly, actual results may differ from estimated
amounts as future confirming events occur. 
Amounts recorded for depreciation, depletion and amortization,
decommissioning costs and obligations and amounts used for impairment
calculations are based on estimates of gross proved plus probable
reserves and future costs required to develop those reserves. By
their nature, these estimates of reserves, including the estimates of
future prices and costs, and the related future cash flows are
subject to measurement uncertainty, and the impact in the financial
statements of future periods could be material. 
The amount of compensation expense accrued for future performance
based compensation arrangements are subject to management's best
estimate of whether or not the performance criteria will be met and
what the ultimate payout will be. 
Tax interpretations, regulations and legislation in the various
jurisdictions in which the Company operates are subject to change. As
such, income taxes are subject to measurement uncertainty. 
c) Presentation currency 
All amounts in these financial statements are expressed in Canadian
dollars, as this is the functional and presentation currency of the
Company. 
d) Cash Equivalents 
Cash equivalents include term deposits or a similar type of
instrument, with a maturity of three months or less when purchased. 
e) Jointly controlled assets 
A jointly controlled asset involves joint control and offers joint
ownership by the Company and other partners of assets contributed to
or acquired for the purpose of the jointly controlled assets, without
the formation of a corporation, partnership or other entity. 
The Company accounts for its share of the jointly controlled assets,
any liabilities it has incurred, its share of any liabilities jointly
incurred with its partners, income from the sale or use of its share
of the joint asset's output, together with its share of the expenses
incurred by the jointly controlled asset and any expenses it incurs
in relation to its interest in the jointly controlled asset. 
f) Exploration and evaluation assets 
Pre-license costs 
Costs incurred prior to obtaining the legal right to explore for
hydrocarbon resources are expensed in the period in which they are
incurred. The Company has no pre-license costs. 
Exploration and evaluation costs  
Once the legal right to explore has been acquired, costs directly
associated with an exploration well are capitalized as exploration
and evaluation intangible assets until the drilling of the well is
complete and the results have been evaluated. All such costs are
subject to technical feasibility, commercial viability and management
review as well as review for impairment at least once a year to
confirm the continued intent to develop or otherwise extract value
from the discovery. The Company has no exploration or evaluation
assets. 
g) Property, plant and equipment 
Oil and gas properties and other property, plant and equipment are
stated at cost, less accumulated depreciation and accumulated
impairment losses. 
The initial cost of an asset comprises its purchase price or
construction cost, any costs directly attributable to bringing the
asset into operation, the initial estimate of the decommissioning
provision and borrowing costs for qualifying assets. The purchase
price or construction cost is the aggregate amount paid and the fair
value of any other consideration given to acquire the asset. Costs
include expenditures on the construction, installation or completion
of infrastructure such as well sites, pipelines and facilities
including activities such as drilling, completion and tie-in costs,
equipment and installation costs, associated geological and human
resource costs, including unsuccessful development or delineation
wells. 
Oil and natural gas asset swaps 
For exchanges or parts of exchanges that involve assets, the exchange
is accounted for at fair value. Assets are then de-recognized at
their current carrying amount.  
Depletion and depreciation  
Oil and natural gas properties are depleted on a unit-of-production
basis over the proved plus probable reserves. All costs related to
oil and natural gas properties (net of salvage value) and estimated
costs of future development of proved plus probable undeveloped
reserves are depleted and depreciated using the unit-of-production
method based on estimated gross proved plus probable reserves as
determined by independent reservoir engineers. For purposes of the
depletion and depreciation calculation, relative volumes of petroleum
and natural gas production and reserves are converted at the energy
equivalent conversion rate of six thousand cubic feet of natural gas
to one barrel of crude oil. 
Other property, plant and equipment are depreciated using a declining
balance method over useful life of 20 years. 
h) Corporate assets 
Corporate assets not related to oil and natural gas exploration and
development activities are recorded at historical costs and
depreciated over their useful life. These assets are not significant
or material in nature. 
i) Impairment of non-financial assets 
The Company assesses at each reporting date whether there is an
indication that an asset may be impaired. If any indication exists,
or when annual impairment testing for an asset is required, the
Company estimates the asset's recoverable amount. An asset's
recoverable amount is the higher of fair value less costs to sell or
value-in-use and is determined for an individual asset, unless the
asset does not generate cash inflows that are largely independent of
those from other assets or groups of assets, in which case the
recoverable amount is assessed as part of a cash generating unit
("CGU"). If the carrying amount of an asset or CGU exceeds its
recoverable amount, the asset or CGU is considered impaired and is
written down to its recoverable amount. In assessing value-in-use,
the estimated future cash flows are discounted to their present value
using a pre-tax discount rate that reflects current market
assessments of the time value of money and the risks specific to the
asset. In determining fair value less costs to sell, recent market
transactions are taken into account, if available. If no such
transactions can be identified, an appropriate valuation model is
used. These calculations are corroborated by valuation multiples,
quoted share prices for publicly traded securities or other available
fair value indicators. 
Impairment losses of continuing operations are recognized in the
income statement. 
An assessment is made at each reporting date as to whether there is
any indication that previously recognized impairment losses may no
longer exist or may have decreased. If such indication exists, the
Company estimates the asset's or cash-generating unit's recoverable
amount. A previously recognized impairment loss is reversed only if
there has been a change in the assumptions used to determine the
asset's recoverable amount since the last impairment loss was
recognized. The reversal is limited so that the carrying amount of
the asset does not exceed its recoverable amount, nor exceed the
carrying amount that would have been determined, net of depreciation,
had no impairment loss been recognized for the asset in prior years. 
j) Leases 
Leases or other arrangements entered into for the use of an asset are
classified as either finance or operating leases. Finance leases
transfer to the Company substantially all of the risks and benefits
incidental to ownership of the leased asset. Assets under finance
lease are amortized over the shorter of the estimated useful life of
the assets and the lease term. All other leases are classified as
operating leases and the payments are amortized on a straight-line
basis over the lease term. 
k) Financial instruments 
Financial instruments within the scope of IAS 39 Financial
Instruments: Recognition and Measurement ("IAS 39") are initially
recognized at fair value on the balance sheet. The Company has
classified each financial instrument into the following categories:
"fair value through profit or loss"; "loans & receivables"; and
"other liabilities". Subsequent measurement of the financial
instruments is based on their classification. Unrealized gains and
losses on fair value through profit or loss financial instruments are
recognized in earnings. The other categories of financial instruments
are recognized at amortized cost using the effective interest rate
method. The Company has made the following classifications: 


 
----------------------------------------------------------------------------
Financial Assets & Liabilities             Category                         
----------------------------------------------------------------------------
Cash                                       Fair value through profit or loss
----------------------------------------------------------------------------
Accounts Receivable                        Loans & receivables              
----------------------------------------------------------------------------
Due from Private Placement                 Loans & receivables              
----------------------------------------------------------------------------
Accounts Payable and Accrued Liabilities   Other liabilities                
----------------------------------------------------------------------------
Provision for Future Performance Based     Other liabilities                
 Compensation                                                               
----------------------------------------------------------------------------
Dividends Payable                          Other liabilities                
----------------------------------------------------------------------------
Long Term Debt                             Other liabilities                
----------------------------------------------------------------------------
Derivative Financial Instruments           Fair value through profit or loss
----------------------------------------------------------------------------

 
Derivative instruments and risk management 
Derivative instruments are utilized by the Company to manage market
risk against volatility in commodity prices. The Company's policy is
not to utilize derivative instruments for speculative purposes. The
Company has chosen to designate its existing derivative instruments
as cash flow hedges. The Company assesses, on an ongoing basis,
whether the derivatives that are used as cash flow hedges are highly
effective in offsetting changes in cash flows of hedged items. All
derivative instruments are recorded on the balance sheet at their
fair value. The effective portion of the gains and losses is recorded
in other comprehensive income until the hedged transaction is
recognized in earnings. When the earnings impact of the underlying
hedged transaction is recognized in the income statement, the fair
value of the associated cash flow hedge is reclassified from other
comprehensive income into earnings. Any hedge ineffectiveness is
immediately recognized in earnings. The fair values of forward
contracts are based on forward market prices.  
Embedded derivatives  
An embedded derivative is a component of a contract that causes some
of the cash flows of the combined instrument to vary in a way similar
to a stand-alone derivative. This causes some or all of the cash
flows that otherwise would be required by the contract to be modified
according to a specified variable, such as interest rate, financial
instrument price, commodity price, foreign exchange rate, a credit
rating or credit index, or other variables to be treated as a
financial derivative. The Company has no contracts containing
embedded derivatives.  
Normal purchase or sale exemption  
Contracts that were entered into and continue to be held for the
purpose of the receipt or delivery of a non-financial item in
accordance with the Company's expected purchase, sale or usage
requirements fall within the exemption from IAS 32 Financial
Instruments: Presentation ("IAS 32") and IAS 39, which is known as
the 'normal purchase or sale exemption'. The Company recognizes such
contracts in its balance sheet only when one of the parties meets its
obligation under the contract to deliver either cash or a
non-financial asset. 
l) Hedging 
The Company uses derivative financial instruments from time to time
to hedge its exposure to commodity price fluctuations. All derivative
financial instruments are initiated within the guidelines of the
Company's risk management policy. This includes linking all
derivatives to specific assets and liabilities on the balance sheet
or to specific firm commitments or forecasted transactions. The
Company enters into hedges of its exposure to petroleum and natural
gas commodity prices by entering into natural gas fixed price
contracts, when it is deemed appropriate. These derivative contracts,
accounted for as hedges, are recognized on the balance sheet.
Realized gains and losses on these contracts are recognized in
revenue and cash flows in the same period in which the revenues
associated with the hedged transaction are recognized. For financial
derivative contracts settling in future periods, a financial asset or
liability is recognized in the balance sheet and measured at fair
value, with changes in fair value recognized in other comprehensive
income. 
m) Inventories 
Inventories are stated at the lower of cost and net realizable value.
Cost of producing oil and natural gas is accounted on a weighted
average basis. This cost includes all costs incurred in the normal
course of business in bringing each product to its present location
and condition.  
n) Provisions 
General 
Provisions are recognized when the Company has a present obligation
(legal or constructive) as a result of a past event, it is probable
that an outflow of resources embodying economic benefits will be
required to settle the obligation and a reliable estimate can be made
of the amount of the obligation. Where the Company expects some or
all of a provision to be reimbursed, the reimbursement is recognized
as a separate asset but only when the reimbursement is virtually
certain. The expense relating to any provision is presented in the
income statement net of any reimbursement. If the effect of the time
value of money is material, provisions are discounted using a current
pre-tax rate that reflects, where appropriate, the risks specific to
the liability. Where discounting is used, the increase in the
provision due to the passage of time is recognized as a finance cost. 
Decommissioning provision 
Decommissioning provision is recognized when the Company has a
present legal or constructive obligation as a result of past events,
and it is probable that an outflow of resources will be required to
settle the obligation, and a reliable estimate of the amount of
obligation can be made. A corresponding amount equivalent to the
provision is also recognized as part of the cost of the related
property, plant and equipment. The amount recognized is the estimated
cost of decommissioning, discounted to its present value using a
risk-free rate. Changes in the estimated timing of decommissioning or
decommissioning cost estimates are dealt with prospectively by
recording an adjustment to the provision, and a corresponding
adjustment to property, plant and equipment. The accretion of the
discount on the decommissioning provision is included as a finance
cost. 
o) Taxes 
Current income tax 
Current income tax assets and liabilities for the current and prior
periods are measured at the amount expected to be recovered from or
paid to the taxation authorities. The tax rates and tax laws used to
compute the amount are those that are enacted or substantively
enacted, at the reporting date, in Canada. 
Current income tax relating to items recognized directly in equity is
recognized in equity and not in the income statement. Management
periodically evaluates positions taken in the tax returns with
respect to situations in which applicable tax regulations are subject
to interpretation and establishes provisions where appropriate. 
Deferred income tax  
The Company follows the liability method of accounting for income
taxes. Under this method, income tax assets and liabilities are
recognized for the estimated tax consequences attributable to
differences between the amounts reported in the financial statements
and their respective tax bases, using enacted or substantively
enacted tax rates expected to apply when the asset is realized or the
liability settled. Deferred income tax assets are only recognized to
the extent it is probable that sufficient future taxable income will
be available to allow the deferred income tax asset to be realized.
Accumulated deferred income tax balances are adjusted to reflect
changes in income tax rates that are enacted or substantively enacted
with the adjustment being recognized in earnings in the period that
the change occurs, except for items recognized in shareholders'
equity. 
p) Revenue recognition 
Revenue from the sale of oil, natural gas and natural gas liquids is
recognized when the significant risks and rewards of ownership have
been transferred, which is when title passes to the purchaser. This
generally occurs when product is physically transferred into a pipe
or other delivery system.  
Gains and losses on disposition 
For all dispositions, either through sale or exchange, gains and
losses are calculated as the difference between the sale or exchange
value in the transaction and the carrying amount of the assets
disposed. Gains and losses on disposition are recognized in earnings
in the same period as the transaction date.  
q) Borrowing costs 
Borrowing costs directly relating to the acquisition, construction or
production of a qualifying capital project under construction are
capitalized and added to the project cost during construction until
such time the assets are substantially ready for their intended use,
which is, when they are capable of commercial production. Where the
funds used to finance a project form part of general borrowings, the
amount capitalized is calculated using a weighted average of rates
applicable to relevant general borrowings of the Company during the
period. All other borrowing costs are recognized in the income
statement in the period in which they are incurred. 
r) Share-based payments 
Liability-settled share-based payments to employees are measured at
the fair value of the liability award at the grant date. A liability
equal to fair value of the payments is accrued over the vesting
period measured at fair value using the Black-Scholes option pricing
model. 
The fair value determined at the grant date of the liability-settled
share-based payments is expensed on a graded basis over the vesting
period, based on the Company's estimate of liability instruments that
will eventually vest. At the end of each reporting period, the
Company revises its estimate of the number of liability instruments
expected to vest. The impact of the revision of the original
estimates, if any, is recognized in the income statement such that
the cumulative expense reflects the revised estimate, with a
corresponding adjustment to the related liability on the balance
sheet. 
s) Earnings per share 
Basic and diluted earnings per share is computed by dividing the net
earnings available to common shareholders by the weighted average
number of shares outstanding during the reporting period. The Company
has no dilutive instruments outstanding which would cause a
difference between the basic and diluted earnings per share.  
t) Shareholders' capital 
Common shares are classified within Shareholders' equity. Incremental
costs directly attributable to the issuance of shares are recognized
as a deduction from Shareholders' capital.  
u) Standards issued but not yet effective 
Peyto has reviewed new and revised accounting pronouncements that
have been issued but are not yet effective and determined that the
following may have an impact on the Company:  
In May 2011, the IASB released the following new standards: IFRS 10,
"Consolidated Financial Statements", IFRS 11, "Joint Arrangements",
IFRS 12, "Disclosures of Interests in Other Entities" and IFRS 13,
"Fair Value Measurement". Each of these standards is to be adopted
for fiscal years beginning January 1, 2013 with earlier adoption
permitted. A brief description of each new standard follows below:  


 
--  IFRS 10, "Consolidated Financial Statements" supercedes IAS 27
    "Consolidation and Separate Financial Statements" and SIC-12
    "Consolidation - Special Purpose Entities". This standard provides a
    single model to be applied in control analysis for all investees
    including special purpose entities. The adoption of this standard is not
    expected to have any impact on Peyto's financial statements. 
    
--  IFRS 11, "Joint Arrangements" divides joint arrangements into two types,
    joint operations and joint ventures, each with their own accounting
    model. All joint arrangements are required to be reassessed on
    transition to IFRS 11 to determine their type to apply the appropriate
    accounting. The adoption of this standard is not expected to have any
    impact on Peyto's financial statements. 
    
--  IFRS 12, "Disclosure of Interests in Other Entities" combines in a
    single standard the disclosure requirements for subsidiaries, associates
    and joint arrangements as well as unconsolidated structured entities.
    The adoption of this standard is not expected to have a material impact
    on Peyto's financial statements. 
    
--  IFRS 13, "Fair Value Measurement" defines fair value, establishes a
    framework for measuring fair value and sets out disclosure requirements
    for fair value measurements. This standard defines fair value as the
    price that would be received to sell an asset or paid to transfer a
    liability in an orderly transaction between market participants at the
    measurement date. The adoption of this standard is not expected to have
    a material impact on Peyto's financial statements. 

 
As of January 1, 2015, Peyto will be required to adopt IFRS 9
"Financial Instruments", which is the result of the first phase of
the International Accounting Standards Board ("IASB") project to
replace IAS 39 "Financial Instruments: Recognition and Measurement".
The new standard replaces the current multiple classification and
measurement models for financial assets and liabilities with a single
model that has only two classification categories: amortized cost and
fair value. Portions of the standard remain in development and the
full impact of the standard on Peyto's Consolidated Financial
Statements will not be known until the project is complete.  
3. Corporate Acquisition 
On August 14, 2012, Peyto completed the acquisition, by plan of
arrangement, of all issued and outstanding common shares of Open
Range. The total consideration of approximately $187.2 million was
paid for by the issuance of 5.4 million common shares of Peyto and
the assumption of Open Range's long-term debt and working capital
deficiency ($190.4 million was allocated to Property, plant &
equipment). Transaction costs of approximately $0.7 million are
included in general and administrative expenses in the Consolidated
Income Statement. 


 
Fair value of net assets acquired                                           
----------------------------------------------------------------------------
Working capital                                                      (1,868)
Property, plant and equipment                                       190,385 
Financial derivative instruments                                     (1,132)
Bank debt                                                           (72,000)
Decommissioning provision                                            (5,127)
Deferred income taxes                                                 1,929 
----------------------------------------------------------------------------
Total net assets acquired                                           112,187 
----------------------------------------------------------------------------
Consideration                                                               
Shares issued (5,404,007 shares)                                    112,187 
----------------------------------------------------------------------------
Total purchase price                                                112,187 
----------------------------------------------------------------------------

 
The above amounts are estimates, which were made by management at the
time of the preparation of these consolidated financial statements
based on information then available. Amendments may be made as
amounts subject to estimates are finalized. 
If Peyto had acquired Open Range on January 1, 2012, the pro-forma
results of the oil and gas sales, net income and comprehensive income
for the period ended December 31, 2012 would have been as follows; 


 
                                        Open Range January                  
                     As Stated December  1, 2012 to August         Pro Forma
                               31, 2012           14, 2012 December 31, 2012
----------------------------------------------------------------------------
Oil and gas sales               380,647             27,756           408,403
Net income                       93,951              1,134            95,085
Comprehensive income             66,966              1,134            68,100
----------------------------------------------------------------------------

 
4. Property, plant and equipment, net 


 
                                                                            
                                                                            
Cost                                                                        
----------------------------------------------------------------------------
At December 31, 2010                                              1,452,242 
----------------------------------------------------------------------------
  Additions                                                         392,309 
  Dispositions                                                         (785)
----------------------------------------------------------------------------
At December 31, 2011                                              1,843,766 
----------------------------------------------------------------------------
  Acquisitions through business combinations                        190,385 
  Additions                                                         466,506 
  Dispositions                                                      (17,649)
----------------------------------------------------------------------------
At December 31, 2012                                              2,483,008 
----------------------------------------------------------------------------
                                                                            
Accumulated depletion and depreciation                                      
----------------------------------------------------------------------------
At December 31, 2010                                                (84,373)
----------------------------------------------------------------------------
  Depletion and depreciation                                       (130,678)
  Dispositions                                                          505 
----------------------------------------------------------------------------
At December 31, 2011                                               (214,546)
----------------------------------------------------------------------------
  Depletion and depreciation                                       (172,338)
  Dispositions                                                          146 
----------------------------------------------------------------------------
At December 31, 2012                                               (386,738)
----------------------------------------------------------------------------
                                                                            
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Carrying amount at December 31, 2012                              2,096,270 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Proceeds received for assets disposed of during 2012 were $21.9
million (2011 - $3.0 million).  
In September 2012, Peyto acquired producing properties for net
proceeds of $16.7 million, which were allocated to property, plant
and equipment of $17.4 million and decommissioning liabilities of
$0.7 million. The properties are in Peyto's core area of production.
The impact on revenue and net income is not significant. 
During 2012 Peyto capitalized $7.8 million (2011 - $5.5 million) of
general and administrative expense directly attributable to
exploration and development activities.  
The Company did not have any indicators of impairment in the current
or prior years.  
5. Long-term debt 


 
----------------------------------------------------------------------------
                                       December 31, 2012   December 31, 2011
----------------------------------------------------------------------------
Bank credit facility                             430,000             470,000
Senior secured notes                             150,000                   -
----------------------------------------------------------------------------
Balance, end of the year                         580,000             470,000
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
The Company has a syndicated $730 million extendible revolving credit
facility with a stated term date of April 28, 2013. The bank facility
is made up of a $30 million working capital sub-tranche and a $700
million production line. The facilities are available on a revolving
basis for a period of at least 364 days and upon the term out date
may be extended for a further 364 day period at the request of the
Company, subject to approval by the lenders. In the event that the
revolving period is not extended, the facility is available on a
non-revolving basis for a further one year term, at the end of which
time the facility would be due and payable. Outstanding amounts on
this facility will bear interest at rates ranging from prime plus
1.0% to prime plus 2.5% determined by the Company's debt to earnings
before interest, taxes, depreciation, depletion and amortization
(EBITDA) ratios ranging from less than 1:1 to greater than 2.5:1. A
General Security Agreement with a floating charge on land registered
in Alberta is held as collateral by the bank. 
On January 3, 2012, Peyto issued CDN $100 million of senior secured
notes pursuant to a note purchase and private shelf agreement. The
notes were issued by way of private placement and rank equally with
Peyto's obligations under its bank facility. The notes are secured
under the General Security Agreement with a floating charge on land
registered in Alberta is held as collateral. The notes have a coupon
rate of 4.39% and mature on January 3, 2019. Interest will be paid
semi-annually in arrears.  
On September 6, 2012, Peyto issued CDN $50 million of senior secured
notes pursuant to a note purchase and private shelf agreement. The
notes were issued by way of private placement and rank equally with
Peyto's obligations under its bank facility. The notes are secured
under the General Security Agreement with a floating charge on land
registered in Alberta is held as collateral. The notes have a coupon
rate of 4.88% and mature on September 6, 2022. Interest will be paid
semi-annually in arrears.  
Upon the issuance of the senior secured notes January 3, 2012, Peyto
became subject to the following financial covenants as defined in the
credit facility and note purchase and private shelf agreements: 


 
--  Senior Debt to EBITDA Ratio will not exceed 3.0 to 1.0 
--  Total Debt to EBITDA Ratio will not exceed 4.0 to 1.0 
--  Interest Coverage Ratio will not be less than 3.0 to 1.0 
--  Total Debt to Capitalization Ratio will not exceed 0.55:1.0 

 
Peyto is in compliance with all financial covenants at December 31,
2012. 
Peyto's total borrowing capacity is $880 million and Peyto's net
credit facility is $730 million.  
The fair value of all senior notes as at December 31, 2012, is $149.9
million compared to a carrying value of $150.0 million.  
Total interest expense for 2012 was $25.4 million (2011 - $21.9
million) and the average borrowing rate for 2012 was 4.7% (2011 -
4.8%).  
6. Decommissioning provision 
The Company makes provision for the future cost of decommissioning
wells, pipelines and facilities on a discounted basis based on the
commissioning of these assets. 
The decommissioning provision represents the present value of the
decommissioning costs related to the above infrastructure, which are
expected to be incurred over the economic life of the assets. The
provisions have been based on the Company's internal estimates on the
cost of decommissioning, the discount rate, the inflation rate and
the economic life of the infrastructure. Assumptions, based on the
current economic environment, have been made which management
believes are a reasonable basis upon which to estimate the future
liability. These estimates are reviewed regularly to take into
account any material changes to the assumptions. However, actual
decommissioning costs will ultimately depend upon the future market
prices for the necessary decommissioning work required which will
reflect market conditions at the relevant time. Furthermore, the
timing of the decommissioning is likely to depend on when production
activities ceases to be economically viable. This in turn will depend
and be directly related to the current and future commodity prices,
which are inherently uncertain. 
The following table reconciles the change in decommissioning
provision: 


 
----------------------------------------------------------------------------
Balance, December 31, 2010                                            24,734
----------------------------------------------------------------------------
New or increased provisions                                            4,764
Accretion of discount                                                    840
Change in discount rate and estimates                                  7,699
----------------------------------------------------------------------------
Balance, December 31, 2011                                            38,037
----------------------------------------------------------------------------
New or increased provisions                                           13,908
Accretion of discount                                                  1,044
Change in discount rate and estimates                                  5,212
----------------------------------------------------------------------------
Balance, December 31, 2012                                            58,201
----------------------------------------------------------------------------
----------------------------------------------------------------------------
  Current                                                                  -
  Non-current                                                         58,201
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
The Company has estimated the net present value of its total
decommissioning provision to be $58.2 million as at December 31, 2012
($38.0 million at December 31, 2011) based on a total future
undiscounted liability of $127.9 million ($101.2 million at December
31, 2011). At December 31, 2012 management estimates that these
payments are expected to be made over the next 50 years with the
majority of payments being made in years 2041 to 2062. The Bank of
Canada's long term bond rate of 2.36 per cent (2.49 per cent at
December 31, 2011) and an inflation rate of 2.0 per cent (2.0 per
cent at December 31, 2011) were used to calculate the present value
of the decommissioning provision. 
7. Shareholders' capital  
Authorized: Unlimited number of voting common shares 
Issued and Outstanding 


 
                                                       Number of     Amount 
Common Shares (no par value)                       Common Shares          $ 
----------------------------------------------------------------------------
Balance, December 31, 2010                           131,875,382    755,831 
----------------------------------------------------------------------------
Common shares issued                                   4,899,000    115,126 
Common share issuance costs (net of tax)                       -     (3,854)
Common shares issued by private placement                906,196     17,150 
Common shares issued pursuant to DRIP                    113,527      1,973 
Common shares issued pursuant to OTUPP                   166,196      2,889 
----------------------------------------------------------------------------
Balance, December 31, 2011                           137,960,301    889,115 
----------------------------------------------------------------------------
Common shares issued                                   4,628,750    115,024 
Common shares issued for acquisition                   5,404,007    112,187 
Common share issuance costs (net of tax)                       -     (3,896)
Common shares issued by private placement                525,655     11,952 
----------------------------------------------------------------------------
Balance, December 31, 2012                           148,518,713  1,124,382 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Peyto reinstated its amended distribution reinvestment and optional
trust unit purchase plan (the "Amended DRIP Plan") effective with the
January 2010 distribution whereby eligible unitholders could elect to
reinvest their monthly cash distributions in additional trust units
at a 5 percent discount to market price. The DRIP plan incorporated
an Optional Trust Unit Purchase Plan ("OTUPP") which provided
unitholders enrolled in the DRIP with the opportunity to purchase
additional trust units from treasury using the same pricing as the
DRIP. The DRIP and the OTUPP plans were cancelled December 31, 2010
with the final shares issued under the plan January 14, 2011. 
On December 31, 2010, Peyto completed a private placement of 655,581
common shares to employees and consultants for net proceeds of $12.4
million ($18.95 per share). These common shares were issued on
January 6, 2011.  
On January 14, 2011, 279,723 common shares (113,527 pursuant to the
DRIP and 166,196 pursuant to the OTUPP) were issued for net proceeds
of $4.9 million.  
On March 25, 2011, Peyto completed a private placement of 250,615
common shares to employees and consultants for net proceeds of $4.7
million ($18.86 per share).  
On December 16, 2011, Peyto closed an offering of 4,899,000 common
shares at a price of $23.50 per common share, receiving proceeds of
$110.1 million (net of issuance costs). 
On December 31, 2011 Peyto completed a private placement of 397,235
common shares to employees and consultants for net proceeds of $9.7
million ($24.52 per share). These common shares were issued on
January 13, 2012. 
On March 23, 2012 Peyto completed a private placement of 128,420
common shares to employees and consultants for net proceeds of $2.2
million ($17.22 per share). 
On August 14, 2012 Peyto issued 5,404,007 common shares which were
valued at $112.2 million (net of issuance costs) ($20.76 per share)
in relation to the closing of a corporate acquisition (Note 3). 
On December 11, 2012, Peyto closed an offering of 4,628,750 common
shares at a price of $24.85 per common share, receiving proceeds of
$110.0 million (net of issuance costs). 
Shares to be issued 
On December 31, 2012 the Company completed a private placement of
154,550 common shares to employees and consultants for net proceeds
of $3.5 million ($22.38 per share). These common shares were issued
on January 7, 2013. 
Per share amounts  
Earnings per share or unit have been calculated based upon the
weighted average number of common shares outstanding for the year
ended December 31, 2012 of 141,093,829 (2011 - 133,196,103). There
are no dilutive instruments outstanding. 
Dividends  
During the year ended December 31, 2012, Peyto declared and paid
dividends of $0.72 per common share or $0.06 per common share per
month, totaling $101.6 million (2011 - $0.72 or $0.06 per share per
month, $96.1 million).  
On January 15, 2013 Peyto declared dividends of $.06 per common share
paid on February 15, 2013. On February 15, 2013, Peyto declared
dividends of $0.06 per common share to be paid to shareholders of
records February 28, 2013. These dividends will be paid March 15,
2013.  
Comprehensive income  
Comprehensive income consists of earnings and other comprehensive
income ("OCI"). OCI comprises the change in the fair value of the
effective portion of the derivatives used as hedging items in a cash
flow hedge. "Accumulated other comprehensive income" is an equity
category comprised of the cumulative amounts of OCI. 
Accumulated hedging gains  
Gains and losses from cash flow hedges are accumulated until settled.
These outstanding hedging contracts are recognized in earnings on
settlement with gains and losses being recognized as a component of
net revenue. Further information on these contracts is set out in
Note 13.  
8. Operating expenses 
The Company's operating expenses include all costs with respect to
day-to-day well and facility operations. Processing and gathering
recoveries related to jointly controlled assets and third party
natural gas reduce operating expenses. 


 
                                                    Years ended December 31 
                                                        2012           2011 
----------------------------------------------------------------------------
Field expenses                                        46,591         38,240 
Processing and gathering recoveries                  (15,331)       (10,861)
----------------------------------------------------------------------------
Total operating expenses                              31,260         27,379 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
9. General and administrative expenses 
General and administrative expenses are reduced by operating and
capital overhead recoveries from operated properties. 


 
                                                    Years ended December 31 
                                                        2012           2011 
----------------------------------------------------------------------------
General and administrative expenses                   12,822         11,402 
Overhead recoveries                                   (8,976)        (6,491)
----------------------------------------------------------------------------
Net general and administrative expenses                3,846          4,911 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
10. Finance costs 


 
                                                     Years ended December 31
                                                         2012           2011
----------------------------------------------------------------------------
Interest expense                                       25,401         21,881
Accretion of discount on provisions                     1,044            840
----------------------------------------------------------------------------
                                                       26,445         22,721
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
11. Future performance based compensation 
The Company awards performance based compensation to employees
annually. The performance based compensation is comprised of reserve
and market value based components. 
Reserve based component 
The reserves value based component is 4% of the incremental increase
in value, if any, as adjusted to reflect changes in debt, equity,
dividends, general and administrative costs and interest, of proved
producing reserves calculated using a constant price at December 31
of the current year and a discount rate of 8%.  
Market based component  
Under the market based component, rights with a three year vesting
period are allocated to employees and key consultants. The number of
rights outstanding at any time is not to exceed 6% of the total
number of common shares outstanding. At December 31 of each year, all
vested rights are automatically cancelled and, if applicable, paid
out in cash. Compensation is calculated as the number of vested
rights multiplied by the total of the market appreciation (over the
price at the date of grant) and associated dividends of a common
share for that period. The 2012 market based component was based on
i) 0.5 million vested rights at an average grant price of $13.50,
average cumulative distributions of $1.44 and a ten day weighted
average closing price of $18.83, ii) 0.6 million vested rights at an
average grant price of $19.13, average cumulative distributions of
$0.72 and a ten day weighted average price of $24.75 and iii) 0.07
million vested rights at an average grant price of $20.63, average
cumulative dividends of $0.48 and a ten day weighted average price of
$22.58.  
The total amount expensed under these plans was as follows: 


 
($000)                                                        2012      2011
----------------------------------------------------------------------------
Market based compensation                                    7,762    17,486
Reserve based compensation                                   4,825     5,210
----------------------------------------------------------------------------
Total market and reserves based compensation                12,587    22,696
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
For the future market based component, compensation costs as at
December 31, 2012 were a recovery of $2.8 million related to 0.6
million non-vested rights with an average grant price of $19.13,
average cumulative dividends of $0.72 and 0.1 million non-vested
rights with an average grant price of $20.63 and average cumulative
dividends of $0.48. (2011 - 0.6 million non-vested rights with an
average grant price of $13.50 and 1.3 million non-vested rights with
an average grant price of $19.13 were $1.2 million). The cumulative
provision for future performance based compensation as at December
31, 2012 was $2.7 million (2011 - $5.6 million).  
The fair values were calculated using a Black-Scholes valuation
model. The principal inputs to the option valuation model were:  


 
                                             December 31         December 31
                                                    2012                2011
----------------------------------------------------------------------------
Share price                                       $22.58              $24.75
Exercise price                           $18.41 - $19.91     $12.06 - $18.41
Expected volatility                                   0%                  0%
Option life                                  1 - 2 years         1 - 2 years
Dividend yield                                        0%                  0%
Risk-free interest rate                            1.08%               0.97%
----------------------------------------------------------------------------

 
Subsequent to December 31, 2012, 3.0 million rights were granted at a
price of $22.58 to be valued at the ten day weighted average market
price at December 31, 2013 and vesting one third on each of December
31, 2013, December 31, 2014 and December 31, 2015. 
12. Income taxes 


 
($000)                                                       2012      2011 
----------------------------------------------------------------------------
Earnings before income taxes                              130,093   168,145 
Statutory income tax rate                                   25.00%    26.50%
----------------------------------------------------------------------------
Expected income taxes                                      32,523    44,558 
Increase (decrease) in income taxes from:                                   
  Corporate income tax rate change                              -    (2,429)
  True-up tax pools                                         1,634    (7,706)
  Resolution of reassessment and other                      1,985     5,539 
----------------------------------------------------------------------------
Total income tax expense (recovery)                        36,142    39,962 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Deferred income tax expense (recovery)                     34,274    35,013 
Current tax expense                                         1,868     4,949 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total income tax expense (recovery)                        36,142    39,962 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Differences between tax base and reported amounts for                       
 depreciable assets                                       207,805   167,282 
Derivative financial instruments                            1,930    11,208 
Share issuance costs                                       (3,095)   (3,083)
Future performance based bonuses                             (684)   (1,389)
Provision for decommission provision                      (14,550)   (9,509)
Cumulative eligible capital                                (6,599)   (7,096)
Attributable crown royalty income carryforward                  -    (4,964)
Tax loss carry-forwards recognized                        (10,566)     (259)
----------------------------------------------------------------------------
Deferred income taxes                                     174,241   152,190 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
At December 31, 2012 the Company has tax pools of approximately
$1,288.0 million (2011 - $998.1 million) available for deduction
against future income. The Company has approximately $42.1 million in
loss carry-forwards (2011 - $0.4 million) available to reduce future
taxable income. 
Canada Revenue Agency ("CRA") conducted an audit of restructuring
costs incurred in the 2003 trust conversion. On September 25, 2008,
the CRA reassessed on the basis that $41 million of these costs were
not deductible and treated them as an eligible capital amount. The
Company filed a notice of objection and the CRA confirmed the
reassessment. Examinations for discovery have been completed. The Tax
Court of Canada had agreed to both parties' request to hold the
Company's appeal in abeyance pending a decision of the Supreme Court
of Canada to hear another taxpayer's appeal. The other appeal raised
issues that are similar in principle to those raised in the Company's
appeal. As the other taxpayer's appeal was unsuccessful with the
Federal Court of Appeal, in 2011, the Company expensed the income tax
of $4.9 million and interest charges of $2.2 million assessed and
paid in 2008. Subsequently, the Alberta Government reassessed the
same time period resulting in income taxes payable of $1.8 million
and interest charges of $1.4 million paid in 2013. 
13. Financial instruments 
Financial instrument classification and measurement 
Financial instruments of the Company carried on the consolidated
balance sheet are carried at amortized cost with the exception of
cash and financial derivative instruments, specifically fixed price
contracts, which are carried at fair value. There are no significant
differences between the carrying amount of financial instruments and
their estimated fair values as at December 31, 2012. 
The fair value of the Company's cash and financial derivative
instruments are quoted in active markets. The Company classifies the
fair value of these transactions according to the following
hierarchy. 


 
--  Level 1 - quoted prices in active markets for identical financial
    instruments. 
--  Level 2 - quoted prices for similar instruments in active markets;
    quoted prices for identical or similar instruments in markets that are
    not active; and model-derived valuations in which all significant inputs
    and significant and significant value drivers are observable in active
    markets. 
--  Level 3 - valuations derived from valuation techniques in which one or
    more significant inputs or significant value drivers are unobservable. 

 
The Company's cash and financial derivative instruments have been
assessed on the fair value hierarchy described above and classified
as Level 1.  
Fair values of financial assets and liabilities 
The Company's financial instruments include cash, accounts
receivable, financial derivative instruments, due from private
placement, current liabilities, provision for future performance
based compensation and long term debt. At December 31, 2012 and 2011,
cash and financial derivative instruments are carried at fair value.
Accounts receivable, due from private placement, current liabilities
and provision for future performance based compensation approximate
their fair value due to their short term nature. The carrying value
of the long term debt approximates its fair value due to the floating
rate of interest charged under the credit facility. 
Market risk  
Market risk is the risk that changes in market prices will affect the
Company's earnings or the value of its financial instruments. Market
risk is comprised of commodity price risk and interest rate risk. The
objective of market risk management is to manage and control
exposures within acceptable limits, while maximizing returns. The
Company's objectives, processes and policies for managing market
risks have not changed from the previous year.  
Commodity price risk management  
The Company is a party to certain derivative financial instruments,
including fixed price contracts. The Company enters into these
contracts with well established counterparties for the purpose of
protecting a portion of its future earnings and cash flows from
operations from the volatility of petroleum and natural gas prices.
The Company believes the derivative financial instruments are
effective as hedges, both at inception and over the term of the
instrument, as the term and notional amount do not exceed the
Company's firm commitment or forecasted transactions and the
underlying basis of the instruments correlate highly with the
Company's exposure.  
Following is a summary of all risk management contracts in place as
at December 31, 2012: 


 
----------------------------------------------------------------------------
Propane                                            Monthly       Price      
Period Hedged                         Type         Volume        (USD)      
----------------------------------------------------------------------------
September 1, 2012 to March 31, 2013   Fixed Price  2,000 bbl     $49.56/bbl 
September 1, 2012 to March 31, 2013   Fixed Price  2,000 bbl     $44.10/ bbl
September 1, 2012 to March 31, 2013   Fixed Price  2,000 bbl     $32.34/ bbl
September 1, 2012 to March 31, 2013   Fixed Price  2,000 bbl     $33.60/ bbl
September 1, 2012 to March 31, 2013   Fixed Price  2,000 bbl     $32.97/ bbl
October 1, 2012 to March 31, 2013     Fixed Price  2,000 bbl     $34.01/ bbl
October 1, 2012 to March 31, 2013     Fixed Price  2,000 bbl     $34.65/ bbl
October 1, 2012 to March 31, 2013     Fixed Price  2,000 bbl     $36.96/ bbl
January 1, 2013 to March 31, 2013     Fixed Price  4,000 bbl     $36.12/bbl 
April 1, 2013 to June 30, 2013        Fixed Price  4,000 bbl     $34.86/bbl 
April 1, 2013 to December 31, 2013    Fixed Price  4,000 bbl     $30.66/bbl 
April 1, 2013 to December 31, 2013    Fixed Price  4,000 bbl     $32.34/bbl 
April 1, 2013 to December 31, 2013    Fixed Price  4,000 bbl     $34.86/bbl 
April 1, 2013 to December 31, 2013    Fixed Price  4,000 bbl     $35.39/bbl 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Butane                                             Monthly       Price      
Period Hedged                         Type         Volume        (USD)      
----------------------------------------------------------------------------
September 1, 2012 to March 31, 2013   Fixed Price  2,000 bbl     $80.64/bbl 
September 1, 2012 to March 31, 2013   Fixed Price  2,000 bbl     $58.38/bbl 
September 1, 2012 to March 31, 2013   Fixed Price  2,000 bbl     $60.06/bbl 
September 1, 2012 to March 31, 2013   Fixed Price  2,000 bbl     $60.06/bbl 
October 1, 2012 to March 31, 2013     Fixed Price  2,000 bbl     $66.36/bbl 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Iso-Butane                                         Monthly       Price      
Period Hedged                         Type         Volume        (USD)      
----------------------------------------------------------------------------
September 1, 2012 to March 31, 2013   Fixed Price  1,000 bbl     $82.32/bbl 
September 1, 2012 to March 31, 2013   Fixed Price  1,000 bbl     $60.48/bbl 
September 1, 2012 to March 31, 2013   Fixed Price  1,000 bbl     $62.58/bbl 
September 1, 2012 to March 31, 2013   Fixed Price  1,000 bbl     $62.58/bbl 
October 1, 2012 to March 31, 2013     Fixed Price  1,000 bbl     $69.30/bbl 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Natural Gas                                                      Price      
Period Hedged                         Type         Daily Volume  (CAD)      
----------------------------------------------------------------------------
April 1, 2011 to March 31, 2013       Fixed Price  5,000 GJ      $4.055/GJ  
April 1, 2011 to March 31, 2013       Fixed Price  5,000 GJ      $3.80/GJ   
June 1, 2011 to March 31, 2013        Fixed Price  5,000 GJ      $4.17/GJ   
June 1, 2011 to March 31, 2013        Fixed Price  5,000 GJ      $4.10/GJ   
June 1, 2011 to March 31, 2013        Fixed Price  5,000 GJ      $4.10/GJ   
November 1, 2011 to March 31, 2013    Fixed Price  5,000 GJ      $4.00/GJ   
April 1, 2012 to October 31, 2013     Fixed Price  5,000 GJ      $4.00/GJ   
April 1, 2012 to October 31, 2013     Fixed Price  5,000 GJ      $4.00/GJ   
April 1, 2012 to October 31, 2013     Fixed Price  5,000 GJ      $4.00/GJ   
April 1, 2012 to October 31, 2013     Fixed Price  5,000 GJ      $4.00/GJ   
April 1, 2012 to March 31, 2013       Fixed Price  5,000 GJ      $2.20/GJ   
April 1, 2012 to March 31, 2013       Fixed Price  5,000 GJ      $2.31/GJ   
April 1, 2012 to October 31, 2013     Fixed Price  5,000 GJ      $2.52/GJ   
April 1, 2012 to March 31, 2014       Fixed Price  5,000 GJ      $3.00/GJ   
May 1, 2012 to October 31, 2013       Fixed Price  5,000 GJ      $2.30/GJ   
August 1, 2012 to March 31, 2014      Fixed Price  5,000 GJ      $3.00/GJ   
August 1, 2012 to October 31, 2014    Fixed Price  5,000 GJ      $3.10/GJ   
November 1, 2012 to October 31, 2013  Fixed Price  5,000 GJ      $2.60/GJ   
November 1, 2012 to October 31, 2013  Fixed Price  5,000 GJ      $3.005/GJ  
November 1, 2012 to October 31, 2013  Fixed Price  5,000 GJ      $3.00/GJ   
November 1, 2012 to March 31, 2014    Fixed Price  5,000 GJ      $2.81/GJ   
November 1, 2012 to March 31, 2014    Fixed Price  5,000 GJ      $3.00/GJ   
November 1, 2012 to March 31, 2014    Fixed Price  5,000 GJ      $3.05/GJ   
November 1, 2012 to March 31, 2014    Fixed Price  5,000 GJ      $3.02/GJ   
November 1, 2012 to October 31, 2014  Fixed Price  5,000 GJ      $3.0575/GJ 
January 1, 2013 to October 31, 2013   Fixed Price  5,000 GJ      $3.42/GJ   
January 1, 2013 to December 31, 2013  Fixed Price  5,000 GJ      $3.105/GJ  
January 1, 2013 to March 31, 2013     Fixed Price  5,000 GJ      $3.32/GJ   
January 1, 2013 to March 31, 2014     Fixed Price  5,000 GJ      $3.00/GJ   
January 1, 2013 to March 31, 2014     Fixed Price  5,000 GJ      $3.02/GJ   
April 1, 2013 to October 31, 2013     Fixed Price  5,000 GJ      $3.205/GJ  
April 1, 2013 to March 31, 2014       Fixed Price  5,000 GJ      $3.105/GJ  
April 1, 2013 to March 31, 2014       Fixed Price  5,000 GJ      $3.53/GJ   
April 1, 2013 to March 31, 2014       Fixed Price  5,000 GJ      $3.45/GJ   
April 1, 2013 to March 31, 2014       Fixed Price  5,000 GJ      $3.50/GJ   
April 1, 2013 to March 31, 2014       Fixed Price  5,000 GJ      $3.08/GJ   
April 1, 2013 to March 31, 2014       Fixed Price  5,000 GJ      $3.17GJ    
November 1, 2013 to October 31, 2014  Fixed Price  5,000 GJ      $3.50/GJ   
----------------------------------------------------------------------------

 
As at December 31, 2012, Peyto had committed to the future sale of
261,000 barrels of natural gas liquids at an average price of $39.86
USD per barrel and 59,810,000 gigajoules (GJ) of natural gas at an
average price of $3.19 per GJ or $3.74 per mcf. Had these contracts
been closed on December 31, 2012, Peyto would have realized a gain in
the amount of $7.7 million. If the AECO gas price on December 31,
2012 were to increase by $1/GJ, the unrealized gain would decrease by
approximately $59.8 million. An opposite change in commodity prices
rates would result in an opposite impact on other comprehensive
income.  
Subsequent to December 31, 2012 Peyto entered into the following
contracts: 


 
----------------------------------------------------------------------------
Propane                                            Monthly       Price      
Period Hedged                         Type         Volume        (USD)      
----------------------------------------------------------------------------
April 1, 2013 to December 31, 2013    Fixed Price  4,000 bbl     $34.44/bbl 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Natural Gas                                                      Price      
Period Hedged                         Type         Daily Volume  (CAD)      
----------------------------------------------------------------------------
April 1, 2013 to March 31, 2014       Fixed Price  5,000 GJ      $3.10/GJ   
April 1, 2013 to October 31, 2014     Fixed Price  5,000 GJ      $3.25/GJ   
April 1, 2013 to October 31, 2014     Fixed Price  5,000 GJ      $3.30/GJ   
April 1, 2013 to October 31, 2014     Fixed Price  5,000 GJ      $3.33/GJ   
April 1, 2013 to October 31, 2014     Fixed Price  7,500 GJ      $3.20/GJ   
April 1, 2013 to October 31, 2014     Fixed Price  5,000 GJ      $3.22/GJ   
April 1, 2013 to October 31, 2014     Fixed Price  5,000 GJ      $3.20/GJ   
April 1, 2013 to October 31, 2014     Fixed Price  5,000 GJ      $3.1925/GJ 
April 1, 2013 to October 31, 2014     Fixed Price  5,000 GJ      $3.25/GJ   
April 1, 2013 to October 31, 2014     Fixed Price  5,000 GJ      $3.30/GJ   
November 1, 2013 to March 31, 2015    Fixed Price  5,000 GJ      $3.6025/GJ 
----------------------------------------------------------------------------

 
Interest rate risk 
The Company is exposed to interest rate risk in relation to interest
expense on its revolving credit facility. Currently, the Company has
not entered into any agreements to manage this risk. If interest
rates applicable to floating rate debt were to have increased by 100
bps (1%) it is estimated that the Company's earnings before income
tax for the year ended December 31, 2012 would decrease by $4.2
million. An opposite change in interest rates will result in an
opposite impact on earnings before income tax.  
Credit risk  
A substantial portion of the Company's accounts receivable is with
petroleum and natural gas marketing entities. Industry standard
dictates that commodity sales are settled on the 25th day of the
month following the month of production. The Company generally
extends unsecured credit to purchasers, and therefore, the collection
of accounts receivable may be affected by changes in economic or
other conditions and may accordingly impact the Company's overall
credit risk. Management believes the risk is mitigated by the size,
reputation and diversified nature of the companies to which they
extend credit. The Company has not previously experienced any
material credit losses on the collection of accounts receivable. Of
the Company's revenue for the year ended December 31, 2012,
approximately 13% was received from one company (December 31, 2011 -
54%, four companies (18%, 13%, 12% and 11%)). Of the Company's
accounts receivable at December 31, 2012, approximately 14% was
receivable from a single company (December 31, 2011 - 15%, one
company). The maximum exposure to credit risk is represented by the
carrying amount on the balance sheet. There are no material financial
assets that the Company considers past due and no accounts have been
written off. 
The Company may be exposed to certain losses in the event of
non-performance by counterparties to commodity price contracts. The
Company mitigates this risk by entering into transactions with
counterparties that have investment grade credit ratings. 
Counterparties to financial instruments expose the Company to credit
losses in the event of non-performance. Counterparties for derivative
instrument transactions are limited to high credit-quality financial
institutions, which are all members of our syndicated credit
facility. 
The Company assesses quarterly if there should be any impairment of
financial assets. At December 31, 2012, there was no impairment of
any of the financial assets of the Company. 
Liquidity risk 
Liquidity risk includes the risk that, as a result of operational
liquidity requirements: 


 
--  The Company will not have sufficient funds to settle a transaction on
    the due date; 
--  The Company will be forced to sell financial assets at a value which is
   less than what they are worth; or 
--  The Company may be unable to settle or recover a financial asset at all.

 
The Company's operating cash requirements, including amounts
projected to complete our existing capital expenditure program, are
continuously monitored and adjusted as input variables change. These
variables include, but are not limited to, available bank lines, oil
and natural gas production from existing wells, results from new
wells drilled, commodity prices, cost overruns on capital projects
and changes to government regulations relating to prices, taxes,
royalties, land tenure, allowable production and availability of
markets. As these variables change, liquidity risks may necessitate
the need for the Company to conduct equity issues or obtain debt
financing. The Company also mitigates liquidity risk by maintaining
an insurance program to minimize exposure to certain losses. 
The following are the contractual maturities of financial liabilities
as at December 31, 2012: 


 
                          less than 1                                     
                               Year       1-2 Years   2-5 Years  Thereafter 
----------------------------------------------------------------------------
Accounts payable and                                                        
 accrued liabilities         164,946                                        
Dividends payable             8,911                                         
Provision for future                                                        
 market and reserves                                                        
 based bonus                  2,677          59                             
Current taxes payable         1,890                                         
Long-term debt(1)                          430,000                          
Senior secured notes                                               150,000  
----------------------------------------------------------------------------
(1) Revolving credit facility renewed annually (see Note 5)                 

 
14. Capital disclosures 
The Company's objectives when managing capital are: (i) to maintain a
flexible capital structure, which optimizes the cost of capital at
acceptable risk; and (ii) to maintain investor, creditor and market
confidence to sustain the future development of the business. 
The Company manages its capital structure and makes adjustments to it
in light of changes in economic conditions and the risk
characteristics of its underlying assets. The Company considers its
capital structure to include Shareholders' equity, debt and working
capital. To maintain or adjust the capital structure, the Company may
from time to time, issue common shares, raise debt, adjust its
capital spending or change dividends paid to manage its current and
projected debt levels. The Company monitors capital based on the
following measures: current and projected debt to earnings before
interest, taxes, depreciation, depletion and amortization ("EBITDA")
ratios, payout ratios and net debt levels. To facilitate the
management of these ratios, the Company prepares annual budgets,
which are updated depending on varying factors such as general market
conditions and successful capital deployment. Currently, all ratios
are within acceptable parameters. The annual budget is approved by
the Board of Directors.  
There were no changes in the Company's approach to capital management
from the previous year. 


 
                                                  December 31    December 31
                                                         2012           2011
----------------------------------------------------------------------------
Shareholders' equity                                1,210,067      1,015,708
Long-term debt                                        580,000        470,000
Working capital (surplus) deficit                      74,884       (40,232)
----------------------------------------------------------------------------
                                                    1,864,951      1,445,476
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
15. Related party transactions 
An officer and director of the Company is a partner of a law firm
that provides legal services to the Company. For the year ended
December 31, 2012, legal fees totaled $1.2 million (2011 - $0.8
million). As at December 31, 2012, an amount due to this firm of $1.2
million was included in accounts payable (2011 - $0.7 million). 
The Company has determined that the key management personnel consists
of it key employees, officers and directors. In addition to the
salaries and directors fees paid to these individuals, the Company
also provides compensation in the form of market and reserve based
bonus to some of these individuals. Compensation expense of $1.3
million is included in general and administrative expenses and $5.0
million in market and reserves based bonus relating to key management
personnel for the year 2012 (2011 - $1.7 million in general and
administrative and $10.1 million in market and reserves based bonus). 
16. Commitments  
Peyto has contractual obligations and commitments as follows: 


 
                            2013    2014    2015    2016    2017  Thereafter
----------------------------------------------------------------------------
Note repayment(1)              -       -       -       -       -     150,000
Interest payments(2)       4,635   6,830   6,830   6,830   6,830      18,785
Transportation                                                              
 commitments              14,033  13,077   9,749   4,575   1,221         924
Operating leases           1,678   1,694     522       -       -           -
----------------------------------------------------------------------------
Total                     20,346  21,601  17,101  11,405   8,051     169,709
----------------------------------------------------------------------------
(1) Long-term debt repayment on senior secured notes                        
(2) Fixed interest payments on senior secured notes                         
                                                                            
Officers                                                                    
                                                                            
  Darren Gee                                    Tim Louie                   
  President and Chief Executive Officer         Vice President, Land        
                                                                            
  Scott Robinson                                David Thomas Vice           
  Executive Vice President and Chief Operating  President, Exploration      
  Officer                                                                   
                                                                            
  Kathy Turgeon                                 Jean-Paul Lachance          
  Vice President, Finance and Chief Financial   Vice President, Exploitation
  Officer                                                                   
                                                                            
  Stephen Chetner                                                           
  Corporate Secretary                                                       
                                                                            
Directors                                                                   
  Don Gray, Chairman                                                        
  Rick Braund                                                               
  Stephen Chetner                                                           
  Brian Davis                                                               
  Michael MacBean, Lead Independent Director                                
  Darren Gee                                                                
  Gregory Fletcher                                                          
  Scott Robinson                                                            
                                                                            
Auditors                                                                    
  Deloitte LLP                                                              
                                                                            
Solicitors                                                                  
  Burnet, Duckworth & Palmer LLP                                            
                                                                            
Bankers                                                                     
  Bank of Montreal                                                          
  Union Bank, Canada Branch                                                 
  Royal Bank of Canada                                                      
  Canadian Imperial Bank of Commerce                                        
  HSBC Bank Canada                                                          
  The Toronto-Dominion Bank                                                 
  Alberta Treasury Branches                                                 
  Canadian Western Bank                                                     
                                                                            
Transfer Agent                                                              
  Valiant Trust Company                                                     
                                                                            
Head Office                                                                 
  1500, 250 - 2nd Street SW                                                 
  Calgary, AB                                                               
  T2P 0C1                                                                   
  Phone: 403.261.6081                                                       
  Fax: 403.451.4100                                                         
  Web: http://www.peyto.com/                                                
  Stock Listing Symbol: PEY.TO                                              
                                                Toronto Stock Exchange      

Contacts:
Peyto Exploration & Development Corp.
1500, 250 - 2nd Street SW
Calgary, AB T2P 0C1
403.261.6081
403.451.4100 (FAX)
www.peyto.com