Peyto Exploration & Development Corp.
TSX : PEY

Peyto Exploration & Development Corp.

March 11, 2015 17:06 ET

Peyto Celebrates a Record Breaking Year in 2014

CALGARY, ALBERTA--(Marketwired - March 11, 2015) - Peyto Exploration & Development Corp. ("Peyto" or the "Company") (TSX:PEY) is pleased to report operating and financial results for the fourth quarter and 2014 fiscal year which set Company records in virtually all categories.

  • Record production - Fourth quarter 2014 production was a record 500 MMCFe/d (83,251 boe/d), with exit production of 85,700 boe/d. Q4 2014 production was up 24% (20% per share) from Q4 2013 while average annual production increased 29% (25% per share) from 59,313 boe/d in 2013 to 76,372 boe/d in 2014.
  • Record reserves - Producing reserves topped 1.2 TCFe (200 mmboes), up 13% from 2013 or 10% per share, while Proved plus Probable Additional reserves exceeded 3.1 TCFe.
  • Record revenues - Annual revenues of $844 million were 47% greater than in 2013 while Q4 2014 revenue of $216 million was 32% higher than the comparable quarter in 2013, both Company records.
  • Record funds from operations - Annual Funds from Operations ("FFO") of $663 million was 51% greater (47% per share) than in 2013 while Q4 2014 FFO of $173 million was 39% higher (33% per share), again both Company records.
  • Record operating margin - Annual cash costs including royalties, operating costs, transportation, G&A and interest totaled $1.08/Mcfe ($6.49/boe) leaving a record 79% of revenue as funds from operations. Fourth quarter 2014 cash costs were $0.93/Mcfe ($5.60/boe), the lowest in Company history, delivering an 80% operating margin.
  • Record capital investment- A record $690 million was invested in building the largest wedge of incremental production in Company history, peaking at 41,000 boe/d, for a cost of $16,800/boe/d. The 2014 capital program was 19% greater than 2013 but yielding similar returns.
  • Record earnings - Annual earnings of $262 million for 2014 were 84% higher (78% per share) than in 2013, while Q4 2014 earnings of $69 million were up 81% from the previous year. The record earnings funded $175 million in dividends to shareholders in 2014.
  • Record well(s) drilled - Peyto drilled a record number of new wells in 2014 with 123 gross (114 net) wells rig released by year end. In addition, the longest horizontal well in Company history was drilled to 6,000 m measured depth. Since inception, the Company has drilled over 1,000 gas wells in the Alberta Deep Basin including over 450 horizontal wells.

2014 in Review

By essentially all measures, 2014 was an outstanding year for Peyto. A record $690 million of capital was invested into the organic development Peyto's many Alberta Deep Basin resource plays. In total, 123 wells were drilled, adding 41,000 boe/d of new production by year end. More importantly, that investment is forecast to deliver a 26%, before tax, internal rate of return. This return is inclusive of the $141 million that was invested in land, seismic and facility expansions. For every location drilled in 2014, 2.5 new locations were recognized in the Company's reserve report, further expanding Peyto's value and drilling inventory. The combination of 26% higher realized prices, 29% greater production and a 79% operating margin led to a record $663 million in funds from operations and $262 million in earnings. These record profits funded $175 million in dividends to shareholders and supported the third dividend increase in the last two years. Over this same two year period, investors have realized a 54% total return.

(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).
(3) Total return is calculated using the December 31, 2012 share price of $22.99 and December 31, 2014 share price of $33.47, along with $2.02/share of dividend.

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.

3 Months Ended
December 31
% 12 Months Ended
December 31
%
2014 2013 Change 2014 2013 Change
Operations
Production
Natural gas (mcf/d) 451,044 361,870 25 % 412,441 317,622 30 %
Oil & NGLs (bbl/d) 8,077 6,984 16 % 7,632 6,376 20 %
Thousand cubic feet equivalent (mcfe/d @ 1:6) 499,505 403,774 24 % 458,232 355,880 29 %
Barrels of oil equivalent (boe/d @ 6:1) 83,251 67,296 24 % 76,372 59,313 29 %
Production per million common shares (boe/d)* 542 452 20 % 498 399 25 %
Product prices
Natural gas ($/mcf) 4.22 3.59 18 % 4.30 3.54 21 %
Oil & NGLs ($/bbl) 55.47 69.84 -21 % 70.68 70.97 0 %
Operating expenses ($/mcfe) 0.31 0.35 -11 % 0.34 0.35 -3 %
Transportation ($/mcfe) 0.13 0.13 0 % 0.13 0.12 8 %
Field netback ($/mcfe) 4.03 3.67 10 % 4.19 3.65 15 %
General & administrative expenses ($/mcfe) 0.06 0.06 0 % 0.03 0.04 -25 %
Interest expense ($/mcfe) 0.19 0.24 -21 % 0.21 0.24 -13 %
Financial ($000, except per share*)
Revenue 216,321 164,455 32 % 843,797 575,845 47 %
Royalties 11,196 10,288 9 % 61,324 40,450 52 %
Funds from operations 173,437 125,164 39 % 662,788 437,742 51 %
Funds from operations per share 1.13 0.84 33 % 4.33 2.94 47 %
Total dividends 49,181 35,702 38 % 174,826 130,898 34 %
Total dividends per share 0.32 0.24 33 % 1.14 0.88 30 %
Payout ratio 29 29 0 % 26 30 -13 %
Earnings 68,597 37,989 81 % 261,778 142,627 83 %
Earnings per diluted share 0.45 0.26 73 % 1.71 0.96 78 %
Capital expenditures 179,697 154,295 16 % 690,389 578,003 19 %
Weighted average common shares outstanding 153,690,808 148,758,923 3 % 153,231,099 148,737,654 3 %
As at December 31
End of period shares outstanding (includes shares to be issued 153,859,728 148,949,448 3 %
Net debt 1,009,508 946,541 7 %
Shareholders' equity 1,551,936 1,200,638 29 %
Total assets 3,127,065 2,555,156 22 %

*all per share amounts using weighted average common shares outstanding

3 Months Ended
December 31
12 Months Ended
December 31
($000 except per share) 2014 2013 2014 2013
Cash flows from operating activities 193,145 116,852 642,531 407,357
Change in non-cash working capital (24,898 ) (1,759 ) (2,046 ) 11,667
Change in provision for performance based compensation (13,987 ) (6,226 ) 3,126 2,421
Performance based compensation 19,177 16,297 19,177 16,297
Funds from operations 173,437 125,164 662,788 437,742
Funds from operations per share 1.13 0.84 4.33 2.94

(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 distributions may vary.

The Peyto Strategy

The Peyto strategy is premised on the belief that not only is natural gas the favoured fuel for the future, but that a real profit can be generated for investors in the exploration and development of natural gas resources if a Company focuses on being the lowest cost, most efficient producer in the industry. As a result, Peyto's focus has always been on cost control, efficiency and profitability. By focusing on costs, rather than revenues, Peyto helps to insulate itself from the volatility in prices inherent in a commodity business. This continuous focus on costs and profitability is evident in Peyto's history throughout various commodity price cycles as illustrated in the following table.

($/Mcfe) 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Average
Sales Price $ 7.32 $ 8.87 $ 8.76 $ 8.93 $ 9.54 $ 6.75 $ 6.15 $ 5.47 $ 4.21 $ 4.43 $ 5.04 100 %
Cost to develop(1) $ (1.60 ) $ (2.39 ) $ (2.95 ) $ (2.11 ) $ (2.88 ) $ (2.26 ) $ (2.10 ) $ (2.12 ) $ (2.22 ) $ (2.35 ) $ (2.25 ) (33 %)
Cost to produce(2) $ (2.21 ) $ (2.76 ) $ (2.66 ) $ (2.75 ) $ (3.01 ) $ (1.75 ) $ (1.63 ) $ (1.35 ) $ (1.05 ) $ (1.06 ) $ (1.08 ) (28 %)
"Profit" $ 3.51 $ 3.72 $ 3.15 $ 4.07 $ 3.65 $ 2.74 $ 2.42 $ 2.00 $ 0.94 $ 1.02 $ 1.71 38 %
Payout(3) $ 2.28 $ 2.81 $ 3.47 $ 3.92 $ 4.25 $ 4.03 $ 3.37 $ 1.24 $ 1.04 $ 1.01 $ 1.05 (38 %)
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.

On average, over the last decade, Peyto has yielded approximately 38% of every dollar of revenue in profit. The consistency and repeatability of this result is a testament to the success of this strategy.

Capital Expenditures

Peyto deployed it's largest ever capital program in 2014, investing $312 million to drill 123 gross (114 net) horizontal gas wells, $183 million to complete them with 1,234 total frac stages, and $54 million to install wellsite equipment and pipelines connecting them to Company owned and operated facilities. Drilling costs per meter of wellbore continued to decrease as execution improved, despite a 5% per year annual inflation in service costs. The table below outlines the past five years of average horizontal drilling and completion costs.

2010 2011 2012 2013 2014
Gross Spuds 52 70 86 99 123
Length (m) 3,762 3,903 4,017 4,179 4,251
Drilling ($MM) $ 2.763 $ 2.823 $ 2.789 $ 2.720 $ 2.660
$ per meter $ 734 $ 723 $ 694 $ 651 $ 626
Completion ($MM) $ 1.358 $ 1.676 $ 1.672 $ 1.625 $ 1.693
$ per meter $ 361 $ 429 $ 416 $ 389 $ 398

Peyto also invested $120 million in the expansion of the Brazeau River, Oldman North, Wildhay and Swanson gas plants adding a total of 105 mmcf/d of gas processing capacity. New land purchases accounted for $13 million, as 44 net sections were added for an average of $459/acre, while 847 km2 of 3-dimensional seismic was acquired for $8.1 million. The following table summarizes the capital investments for the fourth quarter and 2014 fiscal year.

Three Months ended
December 31
Twelve Months ended
December 31
($000) 2014 2013 2014 2013
Land 4,012 1,144 12,750 6,427
Seismic 1,731 683 8,114 2,984
Drilling 80,578 59,825 311,794 254,000
Completions 53,481 46,836 183,471 151,752
Equipping and tie-ins 16,687 12,389 53,777 48,303
Facilities and pipelines 23,208 33,418 120,210 112,054
Acquisitions - - 273 2,483
Total Capital Expenditures 179,697 154,295 690,389 578,003

Reserves

Peyto was successful growing reserves and values in all categories in 2014, despite the year over year reduction in commodity price forecasts. 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.

As at
December 31
%
Change
% Change,
debt adjusted
per share
2014 2013
Reserves (BCFe)
Proved Producing 1,200 1,061 13 % 9 %
Total Proved 2,085 1,827 14 % 10 %
Proved + Probable Additional 3,189 2,807 14 % 10 %
Net Present Value ($millions) Discounted at 5%
Proved Producing $ 3,447 $ 3,156 9 % 7 %
Total Proved $ 4,852 $ 4,544 7 % 3 %
Proved + Probable Additional $ 7,161 $ 6,587 9 % 6 %

†Per share reserves are adjusted for changes in net debt by converting debt to equity using the Dec 31 share price of $33.47 for 2014 and share price of $32.51 for 2013. 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, 2014. The InSite price forecast is available at www.InSitepc.com. For more information on Peyto's reserves, refer to the Press Release dated February 18, 2015 announcing the Year End Reserve Report which is available on the website at 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 2015.

Value Reconciliation

In order to measure the success of all of the capital invested in 2014, it is necessary to quantify the total amount of value added during the year and compare that to the total amount of capital invested. The independent engineers have 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 (ie. commodity prices). Since the capital investments in 2014 were funded from a combination of cash flow, debt and equity, it is necessary to know the change in debt and the change in shares outstanding to see if the change in value is truly accretive to shareholders.

At year-end 2014, Peyto's estimated net debt had increased by $63.0 million to $1.01 billion while the number of shares outstanding had increased by 4.91 million shares to 153.860 million shares. The change in debt includes all of the capital expenditures, as well as any acquisitions, and the total fixed and performance based compensation paid out for the year.

Based on this reconciliation of changes in BT NPV, the Peyto team was able to create $1.0 billion of Proved Producing, $1.2 billion of Total Proven, and $1.8 billion of Proved plus Probable Additional undiscounted reserve value, with $690 million of capital investment. The ratio of capital expenditures to value creation 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 2014, the Proved Producing NPV recycle ratio is 1.5. This means for each dollar invested, the Peyto team was able to create 1.5 new dollars of Proved Producing reserve value.

The historic NPV recycle ratios are presented in the following table.

Value Creation 31-Dec-06 31-Dec-07 31-Dec-08 31-Dec-09 31-Dec-10 31-Dec-11 31-Dec-12 31-Dec-13 31-Dec-14
NPV0 Recycle Ratio
Proved Producing 2.9 4.7 2.1 5.4 3.5 2.4 1.6 1.5 1.5
Total Proved 2.9 5.5 2.5 18.9 6.1 4.7 2.2 2.0 1.7
Proved + Probable Additional 3.8 3.8 2.2 27.1 10.3 6.6 3.2 4.0 2.6

*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. 2014 Proved Producing ($1,017/$690) = 1.5).

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 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.

The following table highlights annual performance ratios both before and after the implementation of horizontal wells in late 2009. These can be used for comparative purposes, but it is cautioned that on their own they do not measure investment success.

2014 2013 2012 2011 2010 2009 2008 2007
Proved Producing
FD&A ($/mcfe) $ 2.25 $ 2.35 $ 2.22 $ 2.12 $ 2.10 $ 2.26 $ 2.88 $ 2.11
RLI (yrs) 7 7 9 9 11 14 14 13
Recycle Ratio 1.9 1.6 1.6 1.9 2.0 1.8 2.3 2.8
Reserve Replacement 183 % 190 % 284 % 230 % 239 % 79 % 110 % 127 %
Total Proved
FD&A ($/mcfe) $ 2.37 $ 2.23 $ 2.04 $ 2.13 $ 2.35 $ 1.73 $ 3.17 $ 1.57
RLI (yrs) 11 12 15 16 17 21 17 16
Recycle Ratio 1.8 1.6 1.7 1.9 1.8 2.3 2.1 3.7
Reserve Replacement 254 % 230 % 414 % 452 % 456 % 422 % 139 % 175 %
Future Development Capital ($ millions) $ 1,721 $ 1,406 $ 1,318 $ 1,111 $ 741 $ 446 $ 222 $ 169
Proved plus Probable Additional
FD&A ($/mcfe) $ 2.01 $ 1.86 $ 1.68 $ 1.90 $ 2.19 $ 1.47 $ 3.88 $ 1.56
RLI (yrs) 18 19 22 22 25 29 23 21
Recycle Ratio 2.1 2.0 2.1 2.1 1.9 2.8 1.7 3.7
Reserve Replacement 328 % 450 % 527 % 585 % 790 % 597 % 122 % 117 %
Future Development Capital ($millions) $ 2,963 $ 2,550 $ 2,041 $ 1,794 $ 1,310 $ 672 $ 390 $ 321
  • 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 ($690.4+$315.2)/(347.419-304.494+27.876) = $2.37/mcfe or $14.20/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 200,068/(83.251x365) = 6.6). 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, by the FD&A costs for the period (eg. Proved Producing (($25.22)/$13.52=1.9). 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 ((347.419-304.494+27.876)/27.876) = 254%).

Quarterly Review

Peyto maintained its pace of activity throughout the final quarter of 2014, drilling 29 gross (27.2 net) wells, completing 36 gross (32.3 net) wells, and installing wellsite equipment to bringing on production 36 gross (32.3 net) wells. In total, $180 million of capital was invested in the quarter, or 26% of the annual capital program, with $81 million spent on drilling, $53 million on completions, $17 million on pipelines, $23 million on facilities and $6 million on lands and seismic.

In total, the 29 wells that were drilled across Peyto's core areas in the Deep Basin targeted the following zones:

Field
Zone Sundance Nosehill Wildhay Ansell Berland Kisku/
Kakwa
Brazeau Total
Wells
Drilled
Cardium 1 1
Notikewin 3 1 1 1 1 4 11
Falher 3 1 2 2 8
Wilrich 1 1 3 3 8
Bluesky 1 1
Total 8 2 5 7 0 1 6 29

Production in the fourth quarter 2014 averaged 83,251 boe/d, up 24% from 67,296 in Q4 2013, made up of 451 mmcf/d of natural gas and 8,077 bbl/d of natural gas liquids. Peyto's realized price for natural gas in Q4 2014 was $4.24/mcf, prior to a $0.02/mcf hedging loss, while it's realized liquids price was $55.13/bbl, prior to a $0.34/bbl hedging gain, yielding a combined revenue stream of $4.71/mcfe. This net sales price was 6% higher than same period a year ago.

Total cash costs for Q4 2014 of $0.93/mcfe, including royalties of $0.24/mcfe, operating costs of $0.31/mcfe, transportation of $0.13/mcfe, G&A of $0.06/mcfe and interest of $0.19/mcfe were the lowest cash costs of any quarter in Peyto's 16 year history. Both operating costs and interest costs were lower than Q4 2013, contributing to this new record.

Peyto generated total funds from operations of $173 million in the quarter, or $3.77/mcfe, equating to an 80% operating margin which was also a new record. DD&A charges of $1.82/mcfe, as well as a provision for current and future performance based compensation and income tax, reduced FFO to earnings of $1.49/mcfe, or a 32% profit margin, which funded the $1.07/mcfe dividend to shareholders.

Marketing

Abundant supply of natural gas continues to outweigh the colder than normal winter weather in North America, and despite average storage levels for this time of year, the current natural gas price outlook is for much lower prices than a year ago. The AECO Monthly strip for the next 12 months is currently trading at close to $2.70/GJ or approximately 40% lower than the $4.70/GJ forecast at this time last year. The same forward strip shows 2016 and 2017 AECO prices of $2.95/GJ and $3.23/GJ, respectively, ultimately reverting to the average of the past 5 years, or $3.36/GJ.

To prevent the short term volatility in natural gas prices from interfering with capital planning, Peyto uses a hedging strategy that is designed to smooth out the short term fluctuations in the price of natural gas through future sales. This is done by selling approximately 35% of the total natural gas production (inclusive of Crown Royalty volumes) on the daily and monthly spot markets while the balance (approximately 65%) is pre-sold or hedged. These hedges are meant to be methodical and consistent and to avoid speculation. In general, this approach will show hedging losses when short term prices climb and hedging gains when short term prices fall. Peyto generally sells its contracts in either the 7 month summer or the 5 month winter season. Peyto has deployed this strategy for over a decade now, which has resulted in $200 million in cumulative gains over the past 13 years. Over the longer term, however, Peyto expects to break even on forward sales and achieve price security for little to no cost.

For 2014, Peyto realized a natural gas price of $3.77/GJ or $4.30/Mcf, for its natural gas sales. This was a combination of 40% being sold in the daily or monthly spot market and 60% having been pre-sold at an average hedged price of $3.56/GJ. The following table summarizes the remaining hedged volumes for the upcoming years effective March 10, 2015:

Future Sales Average Price (CAD)
GJ Mcf* $/GJ $/Mcf*
2015 87,375,000 76,454,202 3.48 3.98
2016 41,250,000 36,094,258 3.26 3.73
2017 4,050,000 3,543,800 2.95 3.37
Total 132,675,000 116,092,260 3.40 3.88

*Assuming historical heat content

As illustrated in the following table, Peyto's unhedged annual realized NGL prices(1) were effectively the same on a year over year basis, and represented 75% of the $94/bbl average Edmonton par oil price in 2014.

Commodity Prices by Component

Three Months ended
December 31
Twelve Months ended
December 31
2014 2013 2014 2013
Natural gas - after hedging ($/GJ) 3.70 3.15 3.77 3.11
Natural gas - after hedging ($/mcf) 4.22 3.59 4.30 3.54
AECO monthly ($/GJ) 3.80 2.99 4.19 3.00
Oil and natural gas liquids ($/bbl)
Condensate ($/bbl) 68.72 84.92 90.31 89.85
Propane ($/bbl) (includes hedging) 20.45 28.55 26.58 25.38
Butane ($/bbl) (includes hedging) 46.44 57.26 53.03 52.73
Pentane ($/bbl) 72.30 90.59 92.86 97.14
Total Oil and natural gas liquids ($/bbl) 55.47 69.84 70.68 70.97
Canadian Light Sweet postings ($/bbl) 74.41 86.28 94.04 92.83
  1. Liquids prices are Peyto realized prices in Canadian dollars adjusted for fractionation and transportation.

Activity Update

Peyto deliberately postponed certain drilling activity in the first two months of 2015 in response to rapidly falling service costs and restrictions in natural gas transportation service. Now that the service sector has begun reducing costs and most of the restrictions in takeaway capacity have been resolved, activity has resumed to Q4 2014 levels.

So far this quarter, 25 gross (24 net) wells have been spud with 18 gross (18 net) wells having been completed and brought onstream. The Company currently has 8 drilling rigs running and plans for continued drilling and completion activity over the traditional April to mid-June breakup period. As with last year, the level and progress of this planned activity will be weather and access dependent. Post breakup, Peyto will be prepared with drill-ready locations and the flexibility to increase the rig count to 10 rigs depending on the service costs, commodity price environment and potential improvement in returns.

Daily production is currently between 83,000 and 85,000 boe/d, with daily variances due mostly to existing wells being taken temporarily offline for safety concerns when new wells, in close proximity, are being completed. As has become the trend in recent years, Peyto is utilizing pad drilling efficiencies wherever possible to minimize environmental impact and to reduce the costs associated with new surface leases and pipelines.

Facility preparations are underway for the continued expansion of several of Peyto's gas plants. The Swanson plant will be expanded in the summer of 2015, adding an additional 40 mmcf/d of processing capacity with the installation of a third refrigeration module and two more compressors. The Wildhay gas plant will be expanded over the third and fourth quarter with another compressor addition, and the Brazeau gas plant will be expanded towards the end of 2015, coincident with a TCPL meter station expansion, with additional compression and possibly additional refrigeration processing equipment. In total, Peyto expects to have close to 750 mmcf/d of processing capacity operational by the end of Q1 2016.

2015 Outlook

Last year was a year of robust commodity prices and enthusiasm in the industry. While still very active, Peyto remained naturally guarded as that enthusiasm could have driven cost inflation and so it required greater vigilance to ensure return expectations were met. This year looks to be the exact opposite. Commodity prices are much lower, industry activity is greatly restrained and costs are deflating. While the focus on returns will remain the same, Peyto is eager to take advantage of this environment, and "be greedy when others are fearful." The Company currently has a deep inventory of profitable drilling locations but looks to opportunistically add to this inventory at a time when prices and competition are expected to be reduced.

The Company expects that with its disciplined, returns driven strategy, its focus on maintaining a low cost advantage, and its experience generating repeatable low risk returns in the Alberta Deep Basin, 2015 could be just as record breaking and should be another year of profitable growth for Peyto.

Conference Call and Webcast

A conference call will be held with the senior management of Peyto to answer questions with respect to the 2014 fourth quarter and full year financial results on Thursday, March 12th, 2015, at 9:00 a.m. Mountain Daylight Time (MDT), or 11:00 a.m. Eastern Daylight Time (EDT). To participate, please call 1-416-340-2216 (Toronto area) or 1-800-355-4959 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 6689421. The replay will be available at 11:00 a.m. MST, 1:00 p.m. EDT Thursday, March 12th, 2015 until midnight EDT on Thursday, March 19th, 2015. The conference call can also be accessed through the internet at www.gowebcasting.com/6257. 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, audited financial statements and related notes, is available at www.peyto.com/news/Q42014MDandA.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 Tuesday, May 12, 2015 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 11, 2015

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 "2015 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.
Balance Sheet
(Amounts in $thousands)
December 31
2014
December 31
2013
Assets
Current assets
Accounts receivable 98,699 83,714
Due from private placement (Note 6) 5,625 6,245
Derivative financial instruments (Note 11) 93,387 -
Prepaid expenses 20,386 5,666
218,097 95,625
Long-term derivative financial instruments (Note 11) 11,677 -
Property, plant and equipment, net (Note 3) 2,897,291 2,459,531
2,908,968 2,459,531
3,127,065 2,555,156
Liabilities
Current liabilities
Accounts payable and accrued liabilities 192,312 155,265
Dividends payable (Note 6) 16,906 11,901
Derivative financial instruments (Note 11) - 26,606
Provision for future performance based compensation (Note 9) 8,225 5,100
217,443 198,872
Long-term debt (Note 4) 925,000 875,000
Long-term derivative financial instruments (Note 11) - 5,180
Provision for future performance based compensation (Note 9) 1,024 3,200
Decommissioning provision (Note 5) 100,815 61,184
Deferred income taxes (Note 10) 330,847 211,082
1,357,686 1,155,646
Equity
Shareholders' capital (Note 6) 1,292,398 1,130,069
Shares to be issued (Note 6) 5,625 6,245
Retained earnings 173,927 86,975
Accumulated other comprehensive income (loss) (Note 6) 79,986 (22,651 )
1,551,936 1,200,638
3,127,065 2,555,156

Approved by the Board of Directors

(signed) "Michael MacBean" (signed) "Darren Gee"
Director Director
Peyto Exploration & Development Corp.
Income Statement
(Amounts in $thousands)
Year ended
December 31
2014 2013
Revenue
Oil and gas sales 910,412 561,645
Realized (loss) gain on hedges (Note 11) (66,615 ) 14,200
Royalties (61,324 ) (40,450 )
Petroleum and natural gas sales, net 782,473 535,395
Expenses
Operating (Note 7) 57,575 45,235
Transportation 21,917 16,221
General and administrative 5,797 5,204
Market and reserves based bonus (Note 9) 19,177 16,297
Future performance based compensation (Note 9) 949 5,564
Interest (Note 8) 34,397 30,991
Accretion of decommissioning provision (Note 5) 1,883 1,544
Depletion and depreciation (Note 3) 291,731 224,976
433,426 346,032
Earnings before taxes 349,047 189,363
Income tax
Deferred income tax expense (Note 10) 87,269 46,736
Earnings for the year 261,778 142,627
Earnings per share (Note 6)
Basic and diluted $ 1.71 $ 0.96
Weighted average number of common shares outstanding (Note 6)
Basic and diluted 153,231,099 148,737,654
Peyto Exploration & Development Corp.
Statement of Comprehensive Income
(Amounts in $thousands)
Year ended
December 31
2014 2013
Earnings for the year 261,778 142,627
Other comprehensive income
Change in unrealized gain (loss) on cash flow hedges 70,234 (25,307 )
Deferred tax (expense) recovery (34,212 ) 9,877
Realized loss (gain) on cash flow hedges 66,615 (14,200 )
Comprehensive Income 364,415 112,997
Peyto Exploration & Development Corp.
Statement of Changes in Equity
(Amounts in $thousands)
Year ended
December 31
2014 2013
Shareholders' capital, Beginning of Year 1,130,069 1,124,382
Equity offering 160,480 -
Common shares issued by private placement 6,997 5,742
Common shares issuance costs (net of tax) (5,148 ) (55 )
Shareholders' capital, End of Year 1,292,398 1,130,069
Common shares to be issued, Beginning of Year 6,245 3,459
Common shares issued (6,245 ) (3,459 )
Common shares to be issued 5,625 6,245
Common shares to be issued, End of Year 5,625 6,245
Retained earnings, Beginning of Year 86,975 75,247
Earnings for the year 261,778 142,627
Dividends (Note 7) (174,826 ) (130,899 )
Retained earnings, End of Year 173,927 86,975
Accumulated other comprehensive income, Beginning of Year (22,651 ) 6,979
Other comprehensive income (loss) 102,637 (29,630 )
Accumulated other comprehensive income, End of Year 79,986 (22,651 )
Total Equity 1,551,936 1,200,638
Peyto Exploration & Development Corp.
Statement of Cash Flows
(Amounts in $thousands)
Year ended
December 31
2014 2013
Cash provided by (used in)
Operating activities
Earnings 261,778 142,627
Items not requiring cash:
Deferred income tax 87,269 46,736
Depletion and depreciation 291,731 224,976
Accretion of decommissioning provision 1,883 1,544
Long term portion of future performance based compensation (2,176 ) 3,141
Change in non-cash working capital related to operating activities 2,046 (11,667 )
642,531 407,357
Financing activities
Issuance of common shares 167,477 5,742
Issuance costs (6,865 ) (73 )
Cash dividends paid (169,821 ) (127,908 )
Increase (decrease) in bank debt - 175,000
Issuance of long term notes 50,000 120,000
40,791 172,761
Investing activities
Additions to property, plant and equipment (690,389 ) (578,003 )
Change in prepaid capital (1,354 ) (5,081 )
Change in non-cash working capital relating to investing activities 8,421 2,966
(683,322 ) (580,118 )
Net increase in cash - -
Cash, beginning of year - -
Cash, end of year - -

The following amounts are included in Cash flows from operating activities:

Cash interest paid 32,130 23,920
Cash taxes paid - 1,800

Peyto Exploration & Development Corp.

Notes to Financial Statements

As at December 31, 2014 and 2013

(Amounts in $ thousands, except as otherwise noted)

  1. Nature of operations

Peyto Exploration & Development Corp. ("Peyto" or the "Company") is a Calgary based oil and natural gas company. 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 10, 2015.

  1. Basis of presentation

These financial statements ("financial statements") as at and for the years ended December 31, 2014 and December 31, 2013 represent the Company's results and financial position in accordance with International Financial Reporting Standards ("IFRS").

  1. 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.

  1. 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, reserve based bonus 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 determination of CGUs requires judgment in defining a group of assets that generate cash inflows that are largely independent of the cash inflows from other assets or groups of assets. CGUs are determined by, shared infrastructure, commodity type, similar exposure to market risks and materiality.

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 amount to be paid out.

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.

  1. Recent Accounting Pronouncement

Certain new standards, interpretations, amendments and improvements to existing standards were issued by the International Accounting Standards Board (IASB) or International Financial Reporting Interpretations Committee (IFRIC) that are mandatory for accounting periods beginning January 1, 2014 or later periods. The affected standards are consistent with those disclosed in Peyto's financial statements as at and for the years ended December 31, 2013 and 2012.

Peyto adopted the following standards on January 1, 2014:

IAS 36 "Impairment of Assets" has been amended to reduce the circumstances in which the recoverable amount of cash generating units "CGUs" are required to be disclosed and clarify the disclosures required when an impairment loss has been recognized or reversed in the period. The retrospective adoption of these amendments will only impact Peyto's disclosures in the notes to the financial statements in periods when an impairment loss or impairment reversal is recognized.

IFRIC 21 "Levies" was developed by the IFRS Interpretations Committee ("IFRIC") and is applicable to all levies imposed by governments under legislation, other than outflows that are within the scope of other standards (e.g., IAS 12 "Income Taxes") and fines or other penalties for breaches of legislation. The interpretation clarifies that an entity recognizes a liability for a levy when the activity that triggers payment, as identified by the relevant legislation, occurs. It also clarifies that a levy liability is accrued progressively only if the activity that triggers payment occurs over a period of time, in accordance with the relevant legislation. Lastly, the interpretation clarifies that a liability should not be recognized before the specified minimum threshold to trigger that levy is reached. The retrospective adoption of this interpretation does not have any impact on Peyto's financial statements

  1. Standards issued but not yet effective

In July 2014, the IASB completed the final elements of IFRS 9 "Financial Instruments." The Standard supersedes earlier versions of IFRS 9 and completes the IASB's project to replace IAS 39 "Financial Instruments: Recognition and Measurement." IFRS 9, as amended, includes a principle-based approach for classification and measurement of financial assets, a single 'expected loss' impairment model and a substantially-reformed approach to hedge accounting. The Standard will come into effect for annual periods beginning on or after January 1, 2018, with earlier adoption permitted. IFRS 9 will be applied by Peyto on January 1, 2018 and the Company is currently evaluating the impact of the standard on its financial statements

In May 2014, the IASB issued IFRS 15 "Revenue from Contracts with Customers," which replaces IAS 18 "Revenue," IAS 11 "Construction Contracts," and related interpretations. The standard is required to be adopted either retrospectively or using a modified transition approach for fiscal years beginning on or after January 1, 2017, with earlier adoption permitted. IFRS 15 will be applied by Peyto on January 1, 2017 and the Company is currently evaluating the impact of the standard on Peyto's financial statements.

  1. Presentation currency

All amounts in these financial statements are expressed in Canadian dollars, as this is the functional and presentation currency of the Company.

  1. Cash Equivalents

Cash equivalents include term deposits or a similar type of instrument, with a maturity of three months or less when purchased.

  1. Jointly controlled operations and assets

Certain activities of the Company are conducted jointly with others where the participants have a direct ownership interest in, and jointly control, the related assets. Accordingly, the accounts of Peyto reflect only its working interest share of revenues, expenses and capital expenditures related to these jointly controlled assets.

Processing recoveries related to joint venture partners reduces operating expenses.

  1. 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.

  1. 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.

  1. 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.

  1. 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.

  1. 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.

  1. 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 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 Compensation Other liabilities
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.

  1. 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 hedging 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 propane and 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 derivative financial 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.

  1. 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.

  1. 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

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.

  1. 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 equity.

  1. 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.

  1. 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.

  1. Share-based payments

Cash-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 cash-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.

  1. 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.

  1. Share capital

Common shares are classified within equity. Incremental costs directly attributable to the issuance of shares are recognized as a deduction from Share capital.

  1. Property, plant and equipment, net
Cost
At December 31, 2012 2,486,722
Additions 578,003
Decommissioning provision additions 1,439
Dispositions -
Prepaid capital 5,081
At December 31, 2013 3,071,245
Additions 690,389
Decommissioning provision additions 37,748
Capital inventory 1,354
At December 31, 2014 3,800,736
Accumulated depletion and depreciation
At December 31, 2012 (386,738 )
Depletion and depreciation (224,976 )
At December 31, 2013 (611,714 )
Depletion and depreciation (291,731 )
At December 31, 2014 (903,445 )
Carrying amount at December 31, 2013 2,459,531
Carrying amount at December 31, 2014 2,897,291

Proceeds received for assets disposed of during 2014 were $nil (2013 - $nil).

During, 2014 Peyto capitalized $7.8 million (2013 - $7.2 million) of general and administrative expense directly attributable to exploration and development activities.

As indicators of impairment existed in the current year an impairment test was done. No impairment existed. In the prior year there were no indicators of impairment so testing was not completed.

  1. Long-term debt
December 31,
2014
December 31,
2013
Bank credit facility 605,000 605,000
Senior unsecured notes 320,000 270,000
Balance, end of the year 925,000 875,000

The Company has a syndicated $1.0 billion extendible unsecured revolving credit facility with a stated term date of April 26, 2017. The bank facility is made up of a $30 million working capital sub-tranche and a $970 million production line. The facilities are available on a revolving basis for a three year period. Borrowings under the facility bear interest at Canadian bank prime or US base rate, or, at Peyto's option, Canadian dollar bankers' acceptances or US dollar LIBOR loan rates, plus applicable margin and stamping fees. The total stamping fees range between 50 basis points and 215 basis points on Canadian bank prime and US base rate borrowings and between 150 basis points and 315 basis points on Canadian dollar bankers' acceptance and US dollar LIBOR borrowings. The undrawn portion of the facility is subject to a standby fee in the range of 30 to 63 basis points.

On April 26, 2013, the security on the notes issued on January 3, 2012 in the amount of $100 million and September 6, 2012 in the amount of $50 million was released pursuant to the amended and restated note purchase and private shelf agreement.

On December 4, 2013, Peyto issued $120 million of senior unsecured notes pursuant to a note purchase agreement. The notes were issued by way of private placement and rank equally with Peyto's obligations under its bank facility. The notes have a coupon rate of 4.50% and mature on December 4, 2020. Interest will be paid semi-annually in arrears.

On July 3, 2014, Peyto issued CDN $50 million of senior unsecured notes pursuant to a note purchase agreement. The notes were issued by way of private placement and rank equally with Peyto's obligations under its bank facility. The notes have a coupon rate of 3.79% and mature on July 3, 2022. Interest is paid semi-annually in arrears.

Peyto is subject to the following financial covenants as defined in the credit facility and note purchase agreements:

  • Long-term debt plus the average working capital deficiency (surplus) at the end of the two most recently completed fiscal quarters adjusted for non-cash items not to exceed 3.0 times trailing twelve month net income before non-cash items, interest and income taxes;
  • Long-term debt and subordinated debt plus the average working capital deficiency (surplus) at the end of the two most recently completed fiscal quarters adjusted for non-cash items not to exceed 4.0 times trailing twelve month net income before non-cash items, interest and income taxes;
  • Trailing twelve months net income before non-cash items, interest and income taxes to exceed 3.0 times trailing twelve months interest expense;
  • Long-term debt and subordinated debt plus the average working capital deficiency (surplus) at the end of the two most recently completed fiscal quarters adjusted for non-cash items not to exceed 55 per cent of the book value of shareholders' equity and long-term debt and subordinated debt.

Peyto is in compliance with all financial covenants and has no subordinated debt as at December 31, 2014.

Peyto's total borrowing capacity is $1.32 billion and Peyto's credit facility is $1.0 billion.

The fair value of all senior notes as at December 31, 2014, is $311.2 million compared to a carrying value of $320.0 million.

Total interest expense for 2014 was $34.4 million (2013 - $30.9 million) and the average borrowing rate for 2014 was 4.04% (2013 - 4.2%).

  1. Decommissioning provision

The Company makes provision for the future cost of decommissioning wells on a discounted basis based on the decommissioning 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, 2012 58,201
New or increased provisions 10,216
Accretion of discount 1,544
Change in discount rate and estimates (8,777 )
Balance, December 31, 2013 61,184
New or increased provisions 11,005
Accretion of discount 1,883
Change in discount rate and estimates 26,743
Balance, December 31, 2014 100,815
Current -
Non-current 100,815

The Company has estimated the net present value of its total decommissioning provision to be $100.8 million as at December 31, 2014 ($61.2 million at December 31, 2013) based on a total future undiscounted liability of $214.1 million ($177.8 million at December 31, 2013). At December 31, 2014 management estimates that these payments are expected to be made over the next 50 years with the majority of payments being made in years 2040 to 2064. The Bank of Canada's long term bond rate of 2.33 per cent (3.24 per cent at December 31, 2013) and an inflation rate of 2.0 per cent (2.0 per cent at December 31, 2013) were used to calculate the present value of the decommissioning provision.

  1. Equity

Share capital

Authorized: Unlimited number of voting common shares

Issued and Outstanding

Common Shares (no par value) Number of
Common Shares
Amount
$
Balance, December 31, 2012 148,518,713 1,124,382
Common shares issued by private placement 240,210 5,742
Common share issuance costs (net of tax) - (55 )
Balance, December 31, 2013 148,758,923 1,130,069
Common shares issued by private placement 211,885 6,997
Equity offering 4,720,000 160,480
Common share issuance costs (net of tax) - (5,148 )
Balance, December 31, 2014 153,690,808 1,292,398

On December 31, 2012, Peyto 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 January 7, 2013.

On March 19, 2013, Peyto completed a private placement of 85,660 common shares to employees and consultants for net proceeds of $2.2 million ($26.65 per share).

On December 31, 2013, Peyto completed a private placement of 190,525 common shares to employees and consultants for net proceeds of $6.2 million ($32.78 per share). These common shares were issued January 8, 2014.

On February 5, 2014, Peyto closed an offering for 4,720,000 common shares at a price of $34.00 per common share, receiving net proceeds of $153.6 million.

On March 17, 2014, Peyto completed a private placement of 21,360 common shares to employees and consultants for net proceeds of $0.8 million ($35.20 per common share).

Shares to be issued

On December 31, 2014, Peyto completed a private placement of 168,920 common shares to employees and consultants for net proceeds of $5.6 million ($33.30 per share). These common shares were issued January 7, 2015.

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, 2014 of 153,231,099 (2013 - 148,737,654). There are no dilutive instruments outstanding.

Dividends

During the year ended December 31, 2014, Peyto declared and paid dividends of $1.14 per common share or $0.08 per common share for the months of January to April 2014, $0.10 per common share for the months of May to October 2014, and $0.11 per common share for the months of November and December totaling $174.8 million (2013 - $0.88 or $0.06 per common share for the months of January to April 2013 and $0.08 per common share for the months of May to December 2013, $130.9 million).

On January 15, 2015, Peyto declared dividends of $0.11 per common share paid on February 13, 2015. On February 13, 2015, Peyto declared dividends of $0.11 per common share to be paid to shareholders of record on February 28, 2015. These dividends will be paid on March 13, 2015.

Accumulated other 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 11.

  1. 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 owned production reduces gross field expenses to Peyto's operating expenses.

Years ended
December 31
2014 2013
Gross field expenses 71,967 58,963
Cost recoveries related to processing and gathering of partner production (14,392 ) (13,728 )
Total operating expenses 57,575 45,235
  1. Finance costs
Years ended
December 31
2014 2013
Interest expense 34,397 30,991
Accretion of decommissioning provisions 1,883 1,544
Total finance costs 36,280 32,535
  1. 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 total amount expensed under these plans was as follows:

($000) 2014 2013
Market based compensation 13,348 14,061
Reserve based compensation 5,829 2,236
Total market and reserves based compensation 19,177 16,297

The fair values were calculated using a Black-Scholes valuation model. The principal inputs to the option valuation model were:

December 31
2014
December 31
2013
Share price $34.34 $32.27
Exercise price $21.70-$31.29 $19.91 - $21.70
Expected volatility 0 % 0 %
Option life 1 - 2 years 1 - 2 years
Forfeiture rate 6 % 10 %
Dividend yield 0 % 0 %
Risk-free interest rate 0 % 0 %

Subsequent to December 31, 2014, 3.4 million rights were granted at a price of $34.34 to be valued at the ten day weighted average market price at December 31, 2015 and vesting 1/3 on each of December 31, 2015, December 31, 2016 and December 31, 2017.

  1. Income taxes
($000) 2014 2013
Earnings before income taxes 349,047 189,363
Statutory income tax rate 25.00 % 25.00 %
Expected income taxes 87,262 47,341
Increase (decrease) in income taxes from:
True-up tax pools 7 (443 )
Resolution of reassessment and other - (162 )
Total income tax expense 87,269 46,736
Deferred income tax expense 87,269 46,736
Current income tax expense - -
Total income tax expense 87,269 46,736
Differences between tax base and reported amounts for depreciable assets (340,090 ) (249,382 )
Derivative financial instruments (26,266 ) 7,947
Share issuance costs 2,171 1,826
Future performance based bonuses 2,312 2,075
Provision for decommission provision 25,204 15,296
Cumulative eligible capital 5,709 6,139
Charitable donations 26 -
Tax loss carry-forwards recognized 87 5,017
Deferred income taxes (330,847 ) (211,082 )

At December 31, 2014 the Company has tax pools of approximately $1,542.0 million (2013 - $1,486.8 million) available for deduction against future income. The Company has $nil in loss carry-forwards (2013 - $19.7 million) available to reduce future taxable income.

  1. Financial instruments

Financial instrument classification and measurement

Financial instruments of the Company carried on the balance sheet are carried at amortized cost with the exception of cash derivative financial 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, 2014.

The fair value of the Company's cash and derivative financial 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, derivative financial instruments, due from private placement, current liabilities, provision for future performance based compensation and long term debt. At December 31, 2014 and 2013, cash and derivative financial 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, 2014:

Natural Gas
Period Hedged
Type Daily
Volume
Price (CAD)
November 1, 2013 to March 31, 2015 Fixed Price 20,000 GJ $3.6025/GJ to 3.94/GJ
April 1, 2014 to March 31, 2015 Fixed Price 140,000 GJ $3.23/GJ- $3.83/GJ
November 1, 2014 to March 31, 2015 Fixed Price 100,000 GJ $3.81/GJ- $4.87GJ
December 1, 2014 to March 31, 2015 Fixed Price 55,000 GJ $3.63/GJ - $4.18/GJ
April 1, 2015 to October 31, 2015 Fixed Price 185,000 GJ $3.24/GJ-$4.05/GJ
April 1, 2015 to March 31, 2016 Fixed Price 95,000 GJ $2.75/GJ- $3.91/GJ
April 1, 2015 to October 31, 2016 Fixed Price 20,000 GJ $3.05/GJ to $4.123/GJ

As at December 31, 2014, Peyto had committed to the future sale of 115,910,000 gigajoules (GJ) of natural gas at an average price of $3.68 per GJ or $4.20 per mcf. Had these contracts been closed on December 31, 2014, Peyto would have realized a gain in the amount of $105.1 million. If the AECO gas price on December 31, 2014 were to increase by $1/GJ, the unrealized gain would increase by approximately $115.9 million. An opposite change in commodity prices rates would result in an opposite impact on other comprehensive income.

Subsequent to December 31, 2014 Peyto entered into the following contracts:

Natural Gas
Period Hedged
Type Daily
Volume
Price (CAD)
April 1, 2015 to October 31, 2015 Fixed Price 5,000 GJ $2.75GJ
April 1, 2015 to March 31, 2016 Fixed Price 20,000 GJ $2.7525/GJ -$2.925GJ
April 1, 2015 to March 31, 2017 Fixed Price 40,000 GJ $2.83GJ -$3.05/GJ
November 1, 2016 to March 31, 2017 Fixed Price 10,000 GJ $2.95/GJ-$2.975/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, 2014 would decrease by $5.6 million. An opposite change in interest rates would 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. Credit limits exceeding $2,000,000 per month are not granted to non-investment grade counterparties unless the Company receives either i) a parental guarantee from an investment grade parent; or ii) an irrevocable letter of credit for two months revenue. 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, 2014, approximately 62% was received from five companies (15%, 14%, 12%, 11%, and 10%) (December 31, 2013 - 62% was received from five companies (15%, 13%, 13%, 11%, and 10%)). Of the Company's accounts receivable at December 31, 2014, approximately 53% was receivable from four companies (15%, 14%, 12%, and 12%) (December 31, 2013 approximately 61% was receivable from five companies (14%, 14%, 11%, 11%, and 11%) 14%. 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's accounts receivable was aged as follows at December 31, 2014:

($000) December 31,
2014
Current (less than 30 days) 91,017
31-60 days 4,444
61-90 days 775
Past due (more than 90 days) 2,433
Balance, December 31, 2014 98,699

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, 2014, 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, 2014:

<1
Year
1-2
Years
3-5
Years
Thereafter
Accounts payable and accrued liabilities 192,312 - - -
Dividends payable 16,906 - - -
Provision for future market and reserves based bonus 8,225 1,024 - -
Long-term debt(1) - - 605,000 -
Unsecured senior notes - - 100,000 220,000
(1) Revolving credit facility renewed annually (see Note 5)

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 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
2014
December 31
2013
Equity 1,551,936 1,200,638
Long-term debt 925,000 875,000
Working capital (surplus) deficit 654 103,247
2,477,590 2,178,885
  1. 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, 2014, legal fees totaled $0.7 million (2013 - $0.7 million). As at December 31, 2014, an amount due to this firm of $0.7 million was included in accounts payable (2013 - $0.7 million).

Certain directors of Peyto are also directors of reporting entities that Peyto engages in transactions with either through the parent or the subsidiary. Peyto is considered related to these reporting entities because of common significant influence. Such services are provided in the normal course of business and at market rates. For the year ended December 31, 2014, expenses totaled $0.8 million (2013 - $0.2 million). As at December 31, 2014, an amount due to these companies of $0.1 million was included in accounts payable (2013 - $0.1 million).

The Company has determined that the key management personnel consists of 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 $1.5 million is included in general and administrative expenses and $7.6 million in market and reserves based bonus relating to key management personnel for the year 2014 (2013 - $1.4 million in general and administrative and $6.5 million in market and reserves based bonus).

  1. Commitments

In addition to those recorded on the Company's balance sheet, the following is a summary of Peyto's contractual obligations and commitments as at December 31, 2014:

2015 2016 2017 2018 2019 Thereafter
Interest payments(1) 14,125 14,125 14,125 14,125 11,930 18,405
Transportation commitments 20,566 20,240 16,298 13,019 9,020 12,773
Operating leases 2,549 1,914 1,654 1,295 1,295 9,062
Other 2,603 - - - - -
Total 39,843 36,279 32,077 28,439 22,245 40,240
(1) Fixed interest payments on senior unsecured notes
  1. Contingencies

On October 31, 2013, Peyto was named as a party to a statement of claim received with respect to transactions between Poseidon Concepts Corp. and Open Range Energy Corp. The allegations against New Open Range contained in the claims described above are based on factual matters that pre-existed the Company's acquisition of New Open Range. The Company has not yet been required to defend either of the actions. If it is required to defend the actions, the Company intends to aggressively protect its interests and the interests of its Shareholders and will seek all available legal remedies in defending the actions.

Officers

Darren Gee
President and Chief Executive Officer
Tim Louie
Vice President, Land
Scott Robinson
Executive Vice President and Chief Operating Officer
David Thomas
Vice President, Exploration
Kathy Turgeon
Vice President, Finance and Chief Financial Officer
Jean-Paul Lachance
Vice President, Exploitation
Lee Curran
Vice President, Drilling and Completions
Stephen Chetner
Corporate Secretary
Todd Burdick
Vice President, Production
Directors
Don Gray, Chairman
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
The Toronto-Dominion Bank
Bank of Nova Scotia
HSBC Bank Canada
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: www.peyto.com
Stock Listing Symbol: PEY.TO
Toronto Stock Exchange

Contact Information

  • Peyto Exploration & Development Corp.
    403.261.6081
    403.451.4100 (FAX)
    www.peyto.com