CST: 26/05/2016 15:20:41   

Peyto Earns $138 Million in 2015 on Capital Investments of $594 Million

84 Days ago

CALGARY, ALBERTA--(Marketwired - Mar 2, 2016) - Peyto Exploration & Development Corp. ("Peyto" or the "Company") (TSX:PEY) is pleased to report operating and financial results for the fourth quarter and 2015 fiscal year. Peyto profitably grew both production and reserves per share in the year while delivering a 79% operating margin(1) and a 20% profit margin(2). An 8% return on capital employed and a 9% return on equity were achieved despite the challenging commodity price environment in 2015. Highlights for the fourth quarter and full year 2015 included:

  • Production exits above 100,000 boe/d - Average annual production increased 12%, or 9% per share, to 514 MMCFe/d (85,674 boe/d) in 2015 up from 458 MMCFe/d (76,372 boe/d) in 2014. Q4 2015 production was up 17%, or 13% per share, from Q4 2014 to 582 MMCFe/d (97,028 boe/d), with exit production of 102,000 boe/d.
  • Reserves per share up 11% - Producing reserves increased 15% to 1.4 TCFe (229 mmboes), up 11% per share, while total P+P reserves increased 11% to 3.5 TCFe (590 mmboes), up 7% per share.
  • Cash costs down 25% - Royalties, operating costs, transportation, G&A and interest expense totaled $0.81/MCFe ($4.87/boe) in 2015 down 25% from $1.08/MCFe in 2014. Total cash costs in 2015 were the lowest in the Company's 17 year history. Fourth quarter 2015 cash costs were further reduced to $0.75/MCFe ($4.54/boe).
  • Funds from operations per share of $3.59 - Annual Funds from Operations ("FFO") of $565 million, or $3.59/share, were down 15% from $663 million in 2014 as a result of a 24% reduction in realized commodity prices offset by a 12% increase in production and a 25% decrease in cash costs. Q4 2015 FFO was $151 million or $0.95/share compared to $173 million, or $1.13/share, in Q4 2014.
  • Capital investments of $594 million - A total of $594 million was invested in the drilling of 140 gross (132 net) wells that contributed 51,000 boe/d of incremental production at year end for a cost of $11,600/boe/d. This was the largest amount of incremental production at the lowest total cost in the Company's history.
  • PDP FD&A half of field netback - All in cost to develop new producing reserves was $1.64/MCFe ($9.83/boe), down 27% from 2014, while the field netback for 2015 averaged $3.24/MCFe ($19.43/boe) resulting in a recycle ratio of 2.0 times. The Company replaced 193% of production with new producing reserves at this ratio.
  • Earnings per share of $0.87 - Annual earnings of $138 million were generated in 2015 despite lower commodity prices and increased provincial corporate tax rates. Fourth quarter 2015 earnings of $43 million ($0.27/share) represented a profit margin (2) of 23% of revenue. Annual dividends of $208 million, or $1.32/share, were paid to shareholders in 2015.

2015 in Review

The year 2015 was both a challenging and rewarding one for Peyto. Realized unhedged natural gas prices were down 38% from the previous year while realized liquids prices were down 43%. As well, take-away restrictions on Trans Canada's intra-Alberta pipeline system reduced annual production by over 4,500 boe/d. Despite these challenges, Peyto was able to reduce both PDP FD&A and cash costs by 27% and 25% respectively, which helped preserve operating and profit margins. Peyto's Wilrich play in the Brazeau River area yielded some of the best well results of the year and helped propel total exit production beyond 102,000 boe/d. In total 140 gross wells were drilled and put on production, while at the same time 171 new locations were added and recognized in Peyto's reserve books. Owned and operated infrastructure was also expanded in the year with over 100 MMcf/d of total processing capacity added at several of Peyto's gas plants. The Company's strict focus on bringing down costs ensured that capital investments for the year continued to deliver solid returns.

(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.

3 Months Ended
December 31
% 12 Months Ended
December 31
%
2015 2014 Change 2015 2014 Change
Operations
Production
Natural gas (Mcf/d) 540,512 451,044 20 % 474,182 412,441 15 %
Oil & NGLs (bbl/d) 6,943 8,077 -14 % 6,643 7,632 -13 %
Thousand cubic feet equivalent (Mcfe/d @ 1:6) 582,167 499,505 17 % 514,042 458,232 12 %
Barrels of oil equivalent (boe/d @ 6:1) 97,028 83,251 17 % 85,674 76,372 12 %
Production per million common shares (boe/d)* 610 542 13 % 544 498 9 %
Product prices
Natural gas ($/Mcf) 3.34 4.22 -21 % 3.58 4.30 -17 %
Oil & NGLs ($/bbl) 39.88 55.47 -28 % 40.40 70.68 -43 %
Operating expenses ($/Mcfe) 0.25 0.31 -19 % 0.29 0.34 -15 %
Transportation ($/Mcfe) 0.16 0.13 23 % 0.16 0.13 23 %
Field netback ($/Mcfe) 3.04 4.03 -25 % 3.24 4.19 -23 %
General & administrative expenses ($/Mcfe) 0.05 0.06 -17 % 0.04 0.03 33 %
Interest expense ($/Mcfe) 0.16 0.19 -16 % 0.18 0.21 -14 %
Financial ($000, except per share*)
Revenue 191,606 216,321 -11 % 717,836 843,797 -15 %
Royalties 6,663 11,196 -40 % 27,019 61,324 -56 %
Funds from operations 151,123 173,437 -13 % 565,473 662,788 -15 %
Funds from operations per share 0.95 1.13 -16 % 3.59 4.33 -17 %
Total dividends 52,456 49,181 7 % 208,149 174,826 19 %
Total dividends per share 0.33 0.32 3 % 1.32 1.14 16 %
Payout ratio 35 29 21 % 37 26 42 %
Earnings 43,406 68,597 -37 % 137,561 261,778 -47 %
Earnings per diluted share 0.27 0.45 -40 % 0.87 1.71 -49 %
Capital expenditures 162,442 179,697 -10 % 593,780 690,389 -14 %
Weighted average common shares outstanding 158,958,273 153,690,808 3 % 157,492,332 153,231,099 3 %
As at December 31
End of period shares outstanding (includes shares to be issued 159,107,303 153,859,728 3 %
Net debt 1,104,602 1,009,508 9 %
Shareholders' equity 1,623,557 1,551,936 5 %
Total assets 3,357,514 3,127,065 7 %

*all per share amounts using weighted average common shares outstanding

3 Months Ended
December 31
12 Months Ended
December 31
($000 except per share) 2015 2014 2015 2014
Cash flows from operating activities 130,483 193,145 530,208 642,531
Change in non-cash working capital 13,168 (24,898 ) 18,109 (2,046 )
Change in provision for performance based compensation (15,911 ) (13,987 ) (6,227 ) 3,126
Performance based compensation 23,383 19,177 23,383 19,177
Funds from operations 151,123 173,437 565,473 662,788
Funds from operations per share 0.95 1.13 3.59 4.33

(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

For the past 17 years, the Peyto strategy has focused on investing shareholders' capital into the profitable development of long life, low cost, low risk natural gas resource plays. Part of Peyto's focus has been on efficiently executing all aspects of exploration and production operations, in order to deliver real, full-cycle returns at the field level. The other part has been on ensuring that costs are managed at the corporate level so that profits are not eroded before they can contribute to shareholder returns. This is accomplished by maintaining a strict focus on cost control, paired with an entrepreneurial, owner attitude that is pervasive throughout the organization. Evidence of the success of this strategy, at various points in the commodity price cycle, can be seen in the following table.

($/Mcfe) 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 17 Year Avg.
Sales Price $ 8.76 $ 8.93 $ 9.54 $ 6.75 $ 6.15 $ 5.47 $ 4.21 $ 4.43 $ 5.04 $ 3.83 $ 5.69
All cash costs not including royalties (2) $ (0.89 ) $ (1.19 ) $ (1.19 ) $ (1.12 ) $ (0.99 ) $ (0.82 ) $ (0.73 ) $ (0.75 ) $ (0.71 ) $ (0.67 ) $ (0.77 )
Capital costs (1) $ (2.95 ) $ (2.11 ) $ (2.88 ) $ (2.26 ) $ (2.10 ) $ (2.12 ) $ (2.22 ) $ (2.35 ) $ (2.25 ) $ (1.64 ) $ (1.96 )
"Profits" $ 4.92 $ 5.63 $ 5.47 $ 3.37 $ 3.06 $ 2.53 $ 1.26 $ 1.33 $ 2.08 $ 1.52 $ 2.96
Royalty Owners $ (1.77 ) $ (1.56 ) $ (1.82 ) $ (0.63 ) $ (0.64 ) $ (0.53 ) $ (0.32 ) $ (0.31 ) $ (0.37 ) $ (0.14 ) $ (0.73 )
Shareholders $ (3.15 ) $ (4.07 ) $ (3.65 ) $ (2.74 ) $ (2.42 ) $ (2.00 ) $ (0.94 ) $ (1.02 ) $ (1.71 ) $ (1.38 ) $ (2.23 )
Div./Dist. paid $ 3.47 $ 3.92 $ 4.25 $ 4.03 $ 3.37 $ 1.24 $ 1.04 $ 1.01 $ 1.05 $ 1.11 $ 1.78
(1) Capital costs to develop new producing reserves is the PDP FD&A
(2) Cash costs not including royalties include Operating costs, Transportation, G&A and Interest.

On average over the last decade and for the Company's 17 year history, the consistency and repeatability of Peyto's execution in the field combined with strict cost control has resulted in nearly 50% of the average sales price being retained in profit. Out of that profit, royalty owners have received approximately 25%, while shareholders, whose capital has been at risk, have received the balance. This level of profitability, in which all stakeholders share, is so strong it is unique in the energy industry and continues to differentiate the Peyto strategy.

Capital Expenditures

Peyto drilled 140 gross (132 net) horizontal wells in 2015, the most in the Company's 17 year history. Dramatically reduced well costs and improved productivity and reserve outcomes contributed to the most successful year since Peyto began using horizontal wells with multi-stage fracs in 2009. The Company invested a total of $288 million in drilling and $173 million in completions, down 19% and 28% on a per well basis, from 2014. Average well length increased slightly to 4,309 m measured depth, while a total of 1,511 frac stages were pumped, or 10.6 stages per well, up from 10.0 stages per well in 2014. Peyto estimates that approximately one quarter of the total 23% reduction in drilling and completion cost can be retained even if service costs increase to previous levels due to permanent changes in well design. Wellsite equipment and tie-ins accounted for $49 million in the year.

The table below outlines the past five years of average horizontal drilling and completion costs.

2010 2011 2012 2013 2014 2015
Gross Spuds 52 70 86 99 123 140
Length (m) 3,762 3,903 4,017 4,179 4,251 4,309
Drilling ($MM) $ 2.763 $ 2.823 $ 2.789 $ 2.720 $ 2.660 $ 2,159
$ per meter $ 734 $ 723 $ 694 $ 651 $ 626 $ 501
Completion ($MM) $ 1.358 $ 1.676 $ 1.672 $ 1.625 $ 1.693 $ 1,212
$ per meter $ 361 $ 429 $ 416 $ 389 $ 398 $ 281

The Company also invested $74.4 million into expanding gas gathering and processing capabilities across Peyto's core areas. The most notable expansion occurred at the Swanson gas plant which included a second processing train and four new compressors taking capacity to 130 MMcf/d. As well, one additional compressor was added at the Oldman North gas plant taking capacity to approximately 125 MMcf/d, and three additional compressors were recently added at the Brazeau gas plant taking capacity to 60 MMcf/d. Two major pipeline projects were completed which expanded the 42km pipeline corridor from the Ansell area to the Swanson gas plant as well as expanded pipeline capacity from the South Brazeau area to the Brazeau gas plant.

Peyto continued to add land through Crown sales and minor property acquisitions in 2015. In total, 58 net sections were acquired for $8.6 million at an average purchase price of $230/acre, down from $459/acre in 2014. The Company also disposed of non-core lands in the Waskahigan and Cutbank areas for $6.3 million. Finally, 478 km2 of 3-dimensional seismic was acquired for $6.5 million to identify new exploration and development drilling inventory on existing and newly acquired acreage.

Peyto's land strategy, which has been a cornerstone of the Company's success, remains the same after 17 years. Lands are only acquired if they contain drilling opportunities that are definable and well understood, and that can meet a strict economic threshold for development within a reasonable timeframe. This has resulted in Peyto's land base being highly prospective "drilling islands" with stacked opportunities that lend themselves to development with horizontal wells and concentrated surface infrastructure.

The following table summarizes the capital investments for the fourth quarter and 2015 fiscal year.

Three Months ended
December 31
Twelve months ended
December 31
($000) 2015 2014 2015 2014
Land - 4,012 5,451 12,750
Seismic 2,158 1,731 6,530 8,114
Drilling 70,589 80,578 287,560 311,794
Completions 53,881 53,481 173,445 183,471
Equipping & Tie-ins 16,221 16,687 48,716 53,777
Facilities & Pipelines 18,953 23,208 74,417 120,210
Acquisitions 36 - 3,143 273
Dispositions - - (6,282 ) -
Office 604 - 800 -
Total Capital Expenditures 162,442 179,697 593,780 690,389

Reserves

Peyto was successful growing reserves in all categories in 2015, 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*
2015 2014
Reserves (BCFe)
Proved Producing 1,375 1,200 15 % 4 %
Total Proved 2,249 2,085 8 % (2 %)
Proved + Probable Additional 3,539 3,189 11 % 0 %
Net Present Value ($ millions) Discounted at 5%
Proved Producing $ 3,175 $ 3,447 (8 %) (18 %)
Total Proved $ 4,354 $ 4,852 (10 %) (18 %)
Proved + Probable Additional $ 6,450 $ 7,161 (10 %) (16 %)

*Per share reserves are adjusted for changes in net debt by converting debt to equity using the Dec 31 share price of $24.87 for 2015 and share price of $33.47 for 2014. 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, 2015. The InSite price forecast is available at www.InSitepc.com. For more information on Peyto's reserves, refer to the Press Release dated February 17, 2016 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 2016.

Value Reconciliation

In order to measure the success of all of the capital invested in 2015, 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 2014 reserve evaluation with this year's price forecast to remove the change in value attributable to commodity prices. 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 2015 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 2015, Peyto's estimated net debt had increased by 9% or $94.5 million to $1.104 billion while the number of shares outstanding had increased by 3% or 5.25 million shares to 159.107 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 $1.4 billion of Proved Producing, $1.9 billion of Total Proven, and $3.0 billion of Proved plus Probable Additional undiscounted reserve value, with $594 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 2015, the Proved Producing NPV recycle ratio is 2.3. This means for each dollar invested, the Peyto team was able to create 2.3 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 31-Dec-15
NPV0 Recycle Ratio
Proved Producing 2.9 4.7 2.1 5.4 3.5 2.4 1.6 1.5 1.5 2.3
Total Proved 2.9 5.5 2.5 18.9 6.1 4.7 2.2 2.0 1.7 3.3
Proved + Probable Additional 3.8 3.8 2.2 27.1 10.3 6.6 3.2 4.0 2.6 5.0

*NPV 0 (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. 2015 Proved Producing ($1,365/$594) = 2.3).

Performance Ratios

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.

2015 2014 2013 2012 2011 2010 2009 2008
Proved Producing
FD&A ($/Mcfe) $ 1.64 $ 2.25 $ 2.35 $ 2.22 $ 2.12 $ 2.10 $ 2.26 $ 2.88
RLI (yrs) 7 7 7 9 9 11 14 14
Recycle Ratio 2.0 1.9 1.6 1.6 1.9 2.0 1.8 2.3
Reserve Replacement 193 % 183 % 190 % 284 % 230 % 239 % 79 % 110 %
Total Proved
FD&A ($/Mcfe) $ 0.72 $ 2.37 $ 2.23 $ 2.04 $ 2.13 $ 2.35 $ 1.73 $ 3.17
RLI (yrs) 11 11 12 15 16 17 21 17
Recycle Ratio 4.5 1.8 1.6 1.7 1.9 1.8 2.3 2.1
Reserve Replacement 188 % 254 % 230 % 414 % 452 % 456 % 422 % 139 %
Future Development Capital ($ millions) $ 1,381 $ 1,721 $ 1,406 $ 1,318 $ 1,111 $ 741 $ 446 $ 222
Proved plus Probable Additional
FD&A ($/Mcfe) $ 0.54 $ 2.01 $ 1.86 $ 1.68 $ 1.90 $ 2.19 $ 1.47 $ 3.88
RLI (yrs) 17 18 19 22 22 25 29 23
Recycle Ratio 6.1 2.1 2.0 2.1 2.1 1.9 2.8 1.7
Reserve Replacement 287 % 328 % 450 % 527 % 585 % 790 % 597 % 122 %
Future Development Capital ($ millions) $ 2,657 $ 2,963 $ 2,550 $ 2,041 $ 1,794 $ 1,310 $ 672 $ 390
  • 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 ($593.8-$339.6)/(374.8-347.4+31.27) = $4.33/boe or $0.72/Mcfe).
  • 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 229,193/(97.028x365) = 6.5). 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 (($19.43)/$9.83=2.0). 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 ((374.8-347.4+31.27)/31.27) = 188%).

Quarterly Review

Peyto maintained a 10 rig program throughout the fourth quarter 2015 with only a minor shutdown over Christmas break. A total of $125 million was invested in the drilling of 35 gross (31.4 net) wells and the completion of 48 gross (45.1 net) wells. In addition, $16 million was invested in wellsite equipment and tie-ins while $19 million was invested in new facilities and pipelines. Seismic acquisitions of $2 million resulted in total capital investment for the quarter of $162.4 million.

Two drilling rigs worked exclusively in the Brazeau area, focused on Wilrich development drilling near the Brazeau gas plant as well as step out Falher and Notikewin locations. The other eight rigs were spread across the greater Sundance and Ansell areas focused primarily on Spirit River targets in the Notikewin, Falher and Wilrich formations as illustrated in the following table.

Field
Zone Sundance Nosehill Wildhay Ansell/
Minehead
Berland Kisku/
Kakwa
Brazeau Total
Wells
Drilled
Cardium
Notikewin 1 2 1 2 6
Falher 2 1 8 1 12
Wilrich 5 6 1 4 16
Bluesky 1 1
Total 9 3 7 9 0 0 7 35

Production in the fourth quarter 2015 averaged 97,028 boe/d, up 17% from 83,251 in Q4 2014, made up of 541 MMcf/d of natural gas and 6,943 bbl/d of natural gas liquids. An average of 1,800 boe/d of production for the quarter was deferred due to restrictions on TCPL's intra-Alberta pipeline system. The Company was able to secure additional temporary firm transportation service in November and December, allowing for unrestricted production with year-end exit levels exceeding 102,000 boe/d. As realized propane prices remained in negative territory, Peyto elected to reject propane recoveries at the Company's various gas plants resulting in higher revenues but lower propane production with approximately 1,700 boe/d remaining in the gas stream.

The Company's realized price for natural gas in Q4 2015 was $2.82/Mcf, prior to a $0.52/Mcf hedging gain, while it's realized liquids price was $39.88/bbl, yielding a combined revenue stream of $3.58/Mcfe. This net sales price was 24% lower than the $4.71/Mcfe realized in Q4 2014.

Peyto set a new record for the lowest total cash costs in its 17 year history in Q4 2015 with $0.75/Mcfe ($4.50/boe). This total included royalties of $0.13/Mcfe, operating costs of $0.25/Mcfe, transportation of $0.16/Mcfe, G&A of $0.05/Mcfe and interest of $0.16/Mcfe. Royalties, operating costs and interest charges were 25% lower than Q4 2014, contributing to this new record. Operating costs for the quarter were 19% lower due to continued efficiency gains through pad drilling and expanded use of remote well surveillance.

Peyto generated total funds from operations of $151 million in the quarter, or $2.83/Mcfe, equating to a 79% operating margin. DD&A charges of $1.64/Mcfe, as well as a provision for current and future performance based compensation and income tax, reduced FFO to earnings of $0.82/Mcfe, or a 23% profit margin. Due to Peyto's industry leading low costs, no impairments were recorded in the quarter. Dividends to shareholders totaled $0.98/Mcfe.

Marketing

Alberta (AECO) natural gas prices in 2015 continued to be pressured by abundant North American supply despite the support of a falling Canadian dollar. In the fourth quarter, extremely warm December weather across much of North America reduced natural gas demand causing prices to fall to their lowest point in the year with AECO daily averaging $2.15/GJ. For 2015, Peyto realized a natural gas price of $3.12/GJ or $3.58/Mcf. This was a combination of approximately 37% being sold in the daily or monthly spot market for $2.56/GJ and 63% having been pre-sold at an average hedged price of $3.45/GJ. In the fourth quarter, this combination was 42% in the spot market at $2.44/GJ and 58% pre-sold at an average hedged price of $3.25/GJ.

As illustrated in the following table, Peyto also realized $40.40/bbl for its blend of natural gas liquids in the year, which represented 71% of the Canadian Light Sweet oil price. In the third and fourth quarters of 2015 Peyto began rejecting propane recoveries due to negative realized propane prices which improved average liquid price offsets to 77% of light oil prices by the fourth quarter.

Commodity Prices by Component

Three Months ended
December 31
Twelve months ended
December 31
2015 2014 2015 2014
Natural gas - after hedging ($/Mcf) 3.34 4.22 3.58 4.30
Natural gas - after hedging ($/GJ) 2.90 3.70 3.12 3.77
AECO monthly ($/GJ) 2.51 3.80 2.62 4.19
Oil and natural gas liquids ($/bbl)
Condensate ($/bbl) 45.29 68.72 51.09 90.31
Propane ($/bbl) (4.82 ) 20.45 (1.99 ) 26.58
Butane ($/bbl) 22.47 46.44 23.55 53.03
Pentane ($/bbl) 49.05 72.30 51.79 92.86
Total Oil and natural gas liquids ($/bbl) 39.88 55.47 40.40 70.68
Canadian Light Sweet postings ($/bbl) 52.02 74.41 56.97 94.04

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

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 $308 million in cumulative gains over the past 14 years.

The following table summarizes the remaining hedged volumes for the upcoming years effective March 2, 2016:

Future Sales Average Price (CAD)
GJ Mcf* $/GJ $/Mcf*
2016 103,440,000 89,947,826 2.85 3.28
2017 70,850,000 61,608,696 2.68 3.08
2018 19,020,000 16,539,130 2.55 2.93
Total 193,310,000 168,095,652 2.76 3.17

*Assuming historical heat content

Activity Update

Peyto began 2016 with 10 drilling rigs active but reduced this count to 8 rigs over the month of January in response to falling natural gas prices. To date, a total of 27 gross (25.3 net) wells have been drilled and 20 gross (19 net) wells have been completed and brought on production. In addition, field construction has commenced on Peyto's Brazeau gas plant expansion which will increase capacity from 60 MMcf/d to 100 MMcf/d by the end of March.

Production to date has averaged 101,000 boe/d with approximately 3,000 boe/d waiting behind pipe for the Brazeau plant expansion. Take away restrictions on TCPL's intra-Alberta pipeline system have eased significantly with up to 50% interruptible service offered in the greater Sundance area. In addition, the Brazeau region has been removed from the Upstream James River restricted area and should no longer be subject to future system capacity constraints.

Peyto closed three small property acquisitions in early 2016, including purchasing an additional 20% interest in Peyto's 60 MMcf/d Galloway natural gas plant, increasing current ownership to 89%. This is the only plant in which Peyto does not own a 100% working interest. This acquisition brings Peyto's working interest capacity in its 9 owned and operated gas plants to approximately 0.75 BCF/d which will be capable of processing over 135,000 boe/d of net, Deep Basin production.

Warm weather has already begun to soften northern Alberta county roads and Peyto plans to taper rig activity commencing early March. In consideration of current commodity prices, Peyto plans to run 4 rigs through breakup on only those areas where pad drilling ensures no cost premium for unpredictable weather conditions.

2016 Revised Budget

Peyto's original 2016 budget of $600 to $650 million, announced November 12, 2015, has been revised to $500 to $550 million to reflect the improved capital efficiency achieved in 2015 and continued improvements expected in 2016. The revised budget, which involves drilling between 125 and 135 gross wells (approximately 95% working interest), will utilize 7 to 8 drilling rigs, with up to 4 rigs drilling during breakup. As before, these locations will be selected from Peyto's internal inventory of over 2,000 Deep Basin locations with a focus on the Lower Cretaceous Spirit River group of formations in the greater Sundance and Brazeau areas.

These new locations are still expected to add between 45,000 boe/d and 50,000 boe/d of new production but at a reduced cost of $10,500 - $11,500/boe/d based on actual and improving cost reductions. A portion of this new production will offset a forecasted 37% base decline, while a portion will grow overall 2016 production to exit between 108,000 boe/d and 113,000 boe/d.

With current AECO natural gas prices forecast to average $1.80/GJ in 2016, along with Canadian Light Sweet crude oil prices of $50/bbl and blended with Peyto's natural gas hedges for 53% of its 2016 gas production at $2.93/GJ, the Company expects to realize revenues of approximately $3.00/Mcfe. After deducting total forecast cash costs of $0.75/Mcfe, the $2.25/Mcfe ($13.50/boe) cash netback is expected to provide funding for the majority of the capital program with Peyto funding the balance from available working capital and bank lines. As always, Peyto will continue to maintain a strong balance sheet and only invest capital if its return objectives can be met.

2016 Outlook

The past year was a race between falling commodity prices, falling activity levels and falling service costs. Peyto, with its industry leading cost structure, has been a key beneficiary of this drop in activity which has translated into much lower costs to build and produce its natural gas resource plays, thus preserving returns on capital invested in the year. The year ahead looks to be a continuation of that same theme. Natural gas and oil prices have continued to fall, as has industry activity. Already, natural gas drilling activity in North America is less than half of what it was at this time last year. As a necessary result, costs too must continue to fall.

The supply response to a warm winter and bloated storage should be swift with fewer than 150 gas-directed drilling rigs running in North America. That's the lowest natural gas rig count in the last 30 years. While Peyto can, and will, continue to be aggressive in this environment, deploying a counter cyclical investment strategy to increase returns, it will not come at the expense of its long term financial health. As always, Peyto will maintain a disciplined, returns focused approach to all capital investments, ensuring that maximum possible returns are generated for shareholders, now and in the future.

Conference Call and Webcast

A conference call will be held with the senior management of Peyto to answer questions with respect to the 2015 fourth quarter and full year financial results on Thursday, March 3rd, 2016, at 9:00 a.m. Mountain Standard Time (MST), or 11:00 a.m. Eastern Standard Time (EST). To participate, please call 1-416-340-2218 (Toronto area) or 1-866-223-7781 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 9125391. The replay will be available at 11:00 a.m. MST, 1:00 p.m. EST Thursday, March 3rd, 2016 until midnight EST on Thursday, March 10th, 2016. The conference call can also be accessed through the internet at www.gowebcasting.com/7262. 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/Q42015MDandA.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, May 18, 2016 at the Metropolitan Conference Centre, Grand Lecture Theatre, 333 - 4th 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.

Peyto Head Office Moving

Effective April 25, 2016, the head office of Peyto will be moving to a new location at Suite 300, 600 - 3rd Avenue SW, Calgary, Alberta, Canada, T2P 0G5.

Darren Gee, President and CEO

March 2, 2016

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 "2016 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
2015
December 31
2014
Assets
Current assets
Accounts receivable 85,525 98,699
Due from private placement (Note 6) 3,769 5,625
Derivative financial instruments (Note 11) 65,169 93,387
Prepaid expenses 12,992 20,386
167,455 218,097
Long-term derivative financial instruments (Note 11) - 11,677
Property, plant and equipment, net (Note 3) 3,190,059 2,897,291
3,190,059 2,908,968
3,357,514 3,127,065
Liabilities
Current liabilities
Accounts payable and accrued liabilities 144,402 192,312
Dividends payable (Note 6) 17,486 16,906
Provision for future performance based compensation (Note 9) 1,998 8,225
163,886 217,443
Long-term debt (Note 4) 1,045,000 925,000
Long-term derivative financial instruments (Note 11) 2,299 -
Provision for future performance based compensation (Note 9) - 1,024
Decommissioning provision (Note 5) 118,882 100,815
Deferred income taxes (Note 10) 403,890 330,847
1,570,071 1,357,686
Equity
Shareholders' capital (Note 6) 1,467,264 1,292,398
Shares to be issued (Note 6) 3,769 5,625
Retained earnings 103,339 173,927
Accumulated other comprehensive income (Note 6) 49,185 79,986
1,623,557 1,551,936
3,357,514 3,127,065

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
2015 2014
Revenue
Oil and gas sales 609,274 910,412
Realized gain (loss) on hedges (Note 11) 108,562 (66,615 )
Royalties (27,019 ) (61,324 )
Petroleum and natural gas sales, net 690,817 782,473
Expenses
Operating (Note 7) 54,121 57,575
Transportation 28,996 21,917
General and administrative 7,105 5,797
Market and reserves based bonus (Note 9) 23,383 19,177
Provision for future performance based compensation (Note 9) (7,251 ) 949
Interest (Note 8) 35,122 34,397
Accretion of decommissioning provision (Note 5) 2,400 1,883
Depletion and depreciation (Note 3) 325,528 291,731
Gain on disposition of assets (Note 3) (2,575 ) -
466,829 433,426
Earnings before taxes 223,988 349,047
Income tax
Deferred income tax expense (Note 10) 86,427 87,269
Earnings for the year 137,561 261,778
Earnings per share (Note 6)
Basic and diluted $ 0.87 $ 1.71
Weighted average number of common shares outstanding (Note 6)
Basic and diluted 157,492,332 153,231,099
Peyto Exploration & Development Corp.
Statement of Comprehensive Income
(Amounts in $ thousands)
Year ended December 31
2015 2014
Earnings for the year 137,561 261,778
Other comprehensive income
Change in unrealized gain on cash flow hedges 66,369 70,234
Deferred tax recovery (expense) 11,392 (34,212 )
Realized loss (gain) on cash flow hedges (108,562 ) 66,615
Comprehensive Income 106,460 364,415
Peyto Exploration & Development Corp.
Statement of Changes in Equity
(Amounts in $ thousands)
Year ended December 31
2015 2014
Shareholders' capital, Beginning of Year 1,292,398 1,130,069
Equity offering 172,517 160,480
Common shares issued by private placement 7,732 6,997
Common shares issuance costs (net of tax) (5,383 ) (5,148 )
Shareholders' capital, End of Year 1,467,264 1,292,398
Common shares to be issued, Beginning of Year 5,625 6,245
Common shares issued (5,625 ) (6,245 )
Common shares to be issued 3,769 5,625
Common shares to be issued, End of Year 3,769 5,625
Retained earnings, Beginning of Year 173,927 86,975
Earnings for the year 137,561 261,778
Dividends (Note 6) (208,149 ) (174,826 )
Retained earnings, End of Year 103,339 173,927
Accumulated other comprehensive income, Beginning of Year 79,986 (22,651 )
Other comprehensive (loss) income (30,801 ) 102,637
Accumulated other comprehensive income, End of Year 49,185 79,986
Total Equity 1,623,557 1,551,936
Peyto Exploration & Development Corp.
Statement of Cash Flows
(Amounts in $ thousands)
Year ended December 31
2015 2014
Cash provided by (used in)
Operating activities
Earnings 137,561 261,778
Items not requiring cash:
Deferred income tax 86,427 87,269
Depletion and depreciation 325,528 291,731
Accretion of decommissioning provision 2,400 1,883
Gain on disposition of assets (2,575 ) -
Long term portion of future performance based compensation (1,024 ) (2,176 )
Change in non-cash working capital related to operating activities (18,109 ) 2,046
530,208 642,531
Financing activities
Issuance of common shares 180,249 167,477
Issuance costs (7,374 ) (6,865 )
Cash dividends paid (207,570 ) (169,821 )
Increase (decrease) in bank debt 20,000 -
Issuance of long term notes 100,000 50,000
85,305 40,791
Investing activities
Additions to property, plant and equipment (593,780 ) (690,389 )
Change in prepaid capital (6,274 ) (1,354 )
Change in non-cash working capital relating to investing activities (15,459 ) 8,421
(615,513 ) (683,322 )
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 37,962 32,130
Cash taxes paid - -
Peyto Exploration & Development Corp.
Notes to Financial Statements
As at December 31, 2015 and 2014
(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 1, 2016.

  1. Basis of presentation

These financial statements ("financial statements") as at and for the years ended December 31, 2015 and December 31, 2014 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, 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 cash generating units ("CGU") 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. CGU 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. 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 for fiscal years beginning on or after January 1, 2018, with earlier adoption permitted. IFRS 15 will be applied by Peyto on January 1, 2018 and the Company is currently evaluating the impact of the standard on Peyto's financial statements.

In January 2016, the IASB issued IFRS 16 Leases, which replaces IAS 17 Leases. For lessees applying IFRS 16,
a single recognition and measurement model for leases would apply, with required recognition of assets and liabilities for most leases. The standard will come into effect for annual periods beginning on or after January 1, 2019, with earlier adoption permitted. The Company is currently evaluating the impact of the standard on the Company'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 and gathering recoveries related to joint operations 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 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 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 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 CGU'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, 2013 3,071,245
Additions 690,389
Decommissioning provision additions 37,748
Dispositions -
Prepaid capital 1,354
At December 31, 2014 3,800,736
Additions 593,966
Decommissioning provision additions 15,667
Prepaid capital 6,274
At December 31, 2015 4,416,643
Accumulated depletion and depreciation
At December 31, 2013 (611,714 )
Depletion and depreciation (291,731 )
At December 31, 2014 (903,445 )
Depletion and depreciation (323,139 )
At December 31, 2015 (1,226,584 )
Carrying amount at December 31, 2014 2,897,291
Carrying amount at December 31, 2015 3,190,059

The gain on disposition of assets relates to disposition of land offset by 2015 land expiries. Proceeds received for assets disposed during 2015 were $6.1 million (2014 - $nil). The net book value of land was $3.5 million (2014 - $nil), calculating a gain of $2.6 million (2014 - $nil).

During, 2015 Peyto capitalized $8.0 million (2014 - $7.8 million) of general and administrative expense directly attributable to exploration and development activities.

At December 31, 2015, an impairment test was performed at the CGU level due to the decline in commodity prices. The Company determined that oil and natural gas properties were not impaired at December 31, 2015 and 2014. The recoverable amount (fair value of the assets less cost of disposal) was determined using a discounted cash flow approach based on Proved Plus Probable Reserves at December 31, 2015, current commodity prices and a risk adjusted after tax discount rate of 9%.

The benchmark prices used in the Company's forecast at December 31, 2015 are outlined as follows:

2016 2017 2018 2019 2020 2021 2022
AECO natural gas ($/MMBtu) 2.71 3.27 3.74 3.87 4.05 4.21 4.49

Prices and costs subsequent to 2022 have been adjusted for estimated annual inflation of 2%.

All else being equal, a 1% increase in the assumed discount rate or a 10% decrease in future planned cash flows would not result in an impairment for the years ended December 31, 2015 and 2014.

  1. Long-term debt
December 31,
2015
December 31,
2014
Bank credit facility 625,000 605,000
Senior unsecured notes 420,000 320,000
Balance, end of the year 1,045,000 925,000

The Company has a syndicated $1.0 billion extendible unsecured revolving credit facility with a stated term date of December 4, 2019. In addition, syndicate members have agreed to add an accordion provision that allows for the pre-approved increase of the facility up to $1.3 billion, at the Company's request, subject to additional commitments by existing facility lenders or by adding new financial institutions to the syndicate. 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 four 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 July 3, 2014, Peyto issued $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.

On May 1, 2015, Peyto issued $100 million 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 4.26% and mature on May 1, 2025. Interest is paid semi-annually in arrears.

The remaining $270 million senior unsecured notes bear interest at 3.79% - 4.88% and have the following maturity dates: $100 million in January 2019, $120 million in December 2020, and $50 million in September 2022.

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, 2015.

Peyto's total borrowing capacity is $1.42 billion and Peyto's credit facility is $1.0 billion.

The fair value of all senior notes as at December 31, 2015, is $417.3 million compared to a carrying value of $420.0 million.

Total interest expense for 2015 was $35.1 million (2014 - $34.4 million) and the average borrowing rate for 2015 was 3.6% (2014 - 4.04%).

  1. Decommissioning provision

The Company makes provision for the future cost of decommissioning wells and facilities on a discounted basis based on the timing of abandonment and reclamation 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, 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
New or increased provisions 20,099
Accretion of discount 2,400
Change in discount rate and estimates (4,432 )
Balance, December 31, 2015 118,882
Current -
Non-current 118,882

The Company has estimated the net present value of its total decommissioning provision to be $118.9 million as at December 31, 2015 (2014 - $100.8 million) based on a total future undiscounted liability of $258.3 million (2014 - $214.1 million). At December 31, 2015 management estimates that these payments are expected to be made over the next 50 years with the majority of payments being made in years 2047 to 2066. The Bank of Canada's long term bond rate of 2.15 per cent (2014 - 2.33 per cent) and an inflation rate of 2.0 per cent (2014 - 2.0 per cent) 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, 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
Common shares issued by private placement 230,465 7,732
Equity offering 5,037,000 172,517
Common share issuance costs (net of tax) - (5,383 )
Balance, December 31, 2015 158,958,273 1,467,264

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).

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.

On March 25, 2015, Peyto completed a private placement of 61,545 common shares to employees and consultants for net proceeds of $2.1 million ($34.23 per common share).

On April 16, 2015, Peyto completed a public offering for 5,037,000 common shares at a price of $34.25 per common share, for net proceeds of $165.2 million.

Shares to be issued

On December 31, 2015, Peyto completed a private placement of 149,030 common shares to employees and consultants for net proceeds of $3.8 million ($25.29 per share). These common shares were issued January 6, 2016.

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, 2015 of 157,492,332 (2014 - 153,231,099). There are no dilutive instruments outstanding.

Dividends

During the year ended December 31, 2015, Peyto declared and paid dividends of $1.32 per common share or $0.11 per common share for the months of January to December 2015 totaling $208.2 million (2014 - $1.14 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).

On January 15, 2016, Peyto declared dividends of $0.11 per common share that were paid on February 12, 2016. On February 12, 2016, Peyto declared dividends of $0.11 per common share to be paid to shareholders of record on February 29, 2016. These dividends will be paid on March 15, 2016.

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
2015 2014
Gross field expenses 69,130 71,967
Cost recoveries related to processing and gathering of partner production (15,009 ) (14,392 )
Total operating expenses 54,121 57,575
  1. Finance costs
Years ended December 31
2015 2014
Interest expense 35,122 34,397
Accretion of decommissioning provisions 2,400 1,883
Total finance costs 37,522 36,280
  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:

Years ended December 31
2015 2014
Market based compensation 12,610 13,348
Reserve based compensation 10,773 5,829
Total market and reserves based compensation 23,383 19,177

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

December 31
2015
December 31
2014
Share price $34.34 $34.34
Exercise price $31.29 $21.70-$31.29
Expected volatility 0 % 0 %
Option life 1 - 2 years 1 - 2 years
Forfeiture rate 7 % 6 %
Dividend yield 0 % 0 %
Risk-free interest rate 0 % 0 %

Subsequent to December 31, 2015, 3.8 million rights were granted at a price of $24.09 to be valued at the ten day weighted average market price at December 31, 2016 and vesting 1/3 on each of December 31, 2016, December 31, 2017 and December 31, 2018.

  1. Income taxes
2015 2014
Earnings before income taxes 223,988 349,047
Statutory income tax rate 26.00 % 25.00 %
Expected income taxes 58,237 87,262
Increase (decrease) in income taxes from:
True-up tax pools (299 ) 7
Rate change 28,158 -
Other 331 -
Total income tax expense 86,427 87,269
Deferred income tax expense 86,427 87,269
Current income tax expense - -
Total income tax expense 86,427 87,269
Differences between tax base and reported amounts for depreciable assets (428,439 ) (340,090 )
Derivative financial instruments (16,975 ) (26,266 )
Share issuance costs 2,993 2,171
Future performance based bonuses 540 2,312
Provision for decommission provision 32,098 25,204
Cumulative eligible capital 5,733 5,709
Charitable donations 56 26
Tax loss carry-forwards recognized 104 87
Deferred income taxes (403,890 ) (330,847 )

At December 31, 2015 the Company has tax pools of approximately $1,598.2 million (2014 - $1,542.0 million) available for deduction against future 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, 2015.

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, 2015 and 2014, 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 excluding senior notes (Note 4) 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, 2015:

Natural Gas
Period Hedged
Type Daily
Volume
Price
(CAD)
April 1, 2015 to March 31, 2016 Fixed Price 190,000 GJ $2.75/GJ to $4.05/GJ
April 1, 2015 to March 31, 2017 Fixed Price 50,000 GJ $2.83/GJ- $3.05/GJ
April 1, 2015 to October 31, 2015 Fixed Price 80,000 GJ $2.75/GJ- $3.91GJ
April 1, 2015 to October 31, 2016 Fixed Price 5,000 GJ $2.89/GJ
May 1, 2015 to March 31, 2017 Fixed Price 5,000 GJ $2.82/GJ
June 1, 2015 to October 31, 2015 Fixed Price 15,000 GJ $2.50/GJ- $2.60GJ
November 1, 2015 to March 31, 2016 Fixed Price 80,000 GJ $2.625/GJ to $3.11/GJ
November 1, 2015 to March 31, 2017 Fixed Price 40,000 GJ $2.84/GJ to $2.98/GJ
December 31, 2015 to March 31, 2016 Fixed Price 5,000 GJ $2.5275/GJ
December 31, 2015 to Mach 31, 2017 Fixed Price 5,000 GJ $2.55/GJ
January 1, 2016 to March 31, 2016 Fixed Price 5,000 GJ $2.62/GJ
January 1, 2016 to March 31, 2018 Fixed Price 5,000 GJ $2.54/GJ
April 1, 2016 to March 31, 2017 Fixed Price 95,000 GJ $2.58/GJ to $3.01/GJ
April 1, 2016 to March 31, 2018 Fixed Price 35,000 GJ $2.5025/GJ to $2.71/GJ
April 1, 2016 to October 31, 2016 Fixed Price 35,000 GJ $3.05/GJ to $3.43/GJ
April 1, 2016 to October 31, 2018 Fixed Price 15,000 GJ $2.54/GJ to $2.60/GJ
November 1, 2016 to March 31, 2017 Fixed Price 5,000 GJ $2.95/GJ
April 1, 2017 to March 31, 2018 Fixed Price 40,000 GJ $2.825/GJ to $2.95/GJ
April 1, 2017 to October 31, 2017 Fixed Price 15,000 GJ $2.74/GJ to $2.98/GJ

As at December 31, 2015, Peyto had committed to the future sale of 177,150,000 gigajoules (GJ) of natural gas at an average price of $2.89 per GJ or $3.32 per mcf. Had these contracts been closed on December 31, 2015, Peyto would have realized a gain in the amount of $62.9 million. If the AECO gas price on December 31, 2015 were to increase by $1/GJ, the unrealized gain would increase by approximately $177.2 million. An opposite change in commodity prices rates would result in an opposite impact on other comprehensive income.

Subsequent to December 31, 2015 Peyto entered into the following contracts:

Natural Gas
Period Hedged
Type Daily
Volume
Price
(CAD)
April 1, 2016 to October 31, 2016 Fixed Price 15,000 GJ $2.40/GJ - $2.45/GJ
April 1, 2016 to March 31, 2018 Fixed Price 25,000 GJ $2.42/GJ - $2.75/GJ
April 1, 2016 to October 31, 2018 Fixed Price 15,000 GJ $2.10/GJ -$2.45GJ
November 1, 2016 to March 31, 2018 Fixed Price 5,000 GJ $2.51/GJ
April 1, 2017 to October 31, 2017 Fixed Price 10,000 GJ $2.40/GJ - $2.50/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, 2015 would decrease by $5.9 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, 2015, approximately 50% was received from four companies (14%, 13%, 12%, and 11%. (December 31, 2014 - 62% was received from five companies (15%, 14%, 12%, 11%, and 10%)). Of the Company's accounts receivable at December 31, 2015, approximately 74% was receivable from five companies (19%, 16%, 15%, 13% and 11%) (December 31, 2014 approximately 53% was receivable from four companies (15%, 14%, 12%, and 12%). 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, 2015:

December 31, 2015
Current (less than 30 days) 79,389
31-60 days 4,946
61-90 days 191
Past due (more than 90 days) 999
Balance, December 31, 2015 85,525

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, 2015, 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, 2015:

< 1
Year
1-2
Years
3-5
Years
Thereafter
Accounts payable and accrued liabilities 144,402 - - -
Dividends payable 17,486 - - -
Provision for future market and reserves based bonus 1,998 - - -
Long-term debt(1) - - 625,000 -
Unsecured senior notes - - 100,000 320,000
(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
2015
December 31
2014
Equity 1,623,557 1,551,936
Long-term debt 1,045,000 925,000
Working capital (surplus) deficit (3,569 ) 654
2,664,988 2,477,590
  1. Related party transactions

Certain directors of Peyto are considered to have significant influence over other reporting entities that Peyto engages in commercial transactions with. Such services are provided in the normal course of business and at market rates. These directors are not involved in the day to day operational decision making of the Company. The dollar value of the transactions between Peyto and each of the related reporting entities is summarized below:

December 31
Director Company Description 2015 2014
Expense Payable Expense Payable
Don Gray Petrus Resources Ltd. Chairman of the Board (15.4 ) 2.0 256.8 4.6
Michael MacBean NCSG Hauling & Rigging Ltd. (subsidiary of NCSG Crane and Heavy Haul) (1) Director, NCSG Crane and Heavy Haul 1,162.2 42.2 588.8 300.7
Stephen Chetner Burnet Duckworth & Palmer LLP Partner 1,199.5 867.2 759.2 744.8
(1) was not a related party until August 2014

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 $2.0 million is included in general and administrative expenses and $11.9 million in market and reserves based bonus relating to key management personnel for the year 2015 (2014 - $1.5 million in general and administrative and $7.6 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, 2015:

2016 2017 2018 2019 2020 Thereafter
Interest payments(1) 18,385 18,385 18,385 16,190 13,995 27,840
Transportation commitments 24,020 23,409 32,673 30,148 23,192 96,290
Operating leases 1,914 1,654 1,295 1,295 1,295 7,767
Other 2,172 - - - - -
Total 46,491 43,448 52,353 47,633 38,482 131,897
(1) Fixed interest payments on senior unsecured notes
  1. Contingencies

On October 1, 2013, two shareholders (the "Plaintiffs") of Poseidon Concepts Corp. ("Poseidon") filed an application to seek leave of the Alberta Court of Queen's Bench (the "Court") to pursue a class action lawsuit against the Company, as a successor to new Open Range Energy Corp. ("New Open Range"). The proposed action contains various claims relating to alleged misrepresentations in disclosure documents of Poseidon (not New Open Range), which claims are also alleged in class action lawsuits filed in Alberta, Ontario, and Quebec earlier in 2013 against Poseidon and certain of its current and former directors and officers, and underwriters involved in the public offering of common shares of Poseidon completed in February 2012. The proposed class action seeks various declarations and damages including compensatory damages which the Plaintiffs estimate at $651 million and punitive damages which the Plaintiffs estimate at $10 million, which damage amounts appear to be duplicative of damage amounts claimed in the class actions against Poseidon, certain of its current and former directors and officers, and underwriters.

New Open Range was incorporated on September 14, 2011 solely for purposes of participating in a plan of arrangement with Poseidon (formerly named Open Range Energy Corp. ("Old Open Range")), which was completed on November 1, 2011. Pursuant to such arrangement, Poseidon completed a corporate reorganization resulting in two separate publicly-traded companies: Poseidon, which continued to carry on the energy service and supply business; and New Open Range, which carried on Poseidon's former oil and gas exploration and production business. The Company acquired all of the issued and outstanding common shares of New Open Range on August 14, 2012. On April 9, 2013, Poseidon obtained creditor protection under the Companies' Creditor Protection Act.

On October 31, 2013, Poseidon filed a lawsuit with the Court naming the Company as a co-defendant along with the former directors and officers of Poseidon, the former directors and officers of Old Open Range and the former directors and officers of New Open Range. Poseidon claims, among other things, that the Company is vicariously liable for the alleged wrongful acts and breaches of duty of the directors, officers and employees of New Open Range.

On July 3, 2014, the Plaintiffs filed a lawsuit with the Court against KPMG LLP, Poseidon's and Old Open Range's former auditors, making allegations substantially similar to those in the other claims. On July 29, 2014, KPMG LLP filed a statement of defense and a third party claim against Poseidon, the Company and the former directors and officers of Poseidon. The third party claim seeks, among other things, an indemnity, or alternatively contribution, from the third party defendants with respect to any judgment awarded against KPMG LLP.

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. Although the outcome of this matter is not determinable at this time, the Company believes that this claim will not have a material adverse effect on the Company's financial position or results of operations as the Company believes the claims against it are unprecedented and are without merit.

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
Alberta Treasury Branches
Canadian Western Bank
Transfer Agent
Computershare
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

Peyto Exploration & Development Corp.
403.261.6081
403.451.4100
www.peyto.com