Peyto Posts 18th Consecutive Year of Profits, Earnings Per Share Up 55%

CALGARY, Alberta, Feb. 28, 2018 (GLOBE NEWSWIRE) --

Peyto Exploration & Development Corp. (TSX:PEY) (“Peyto” or the “Company”) is pleased to report operating and financial results for the fourth quarter and 2017 fiscal year. Peyto achieved a 75% operating margin1 and a 23% profit margin2 in 2017, while also generating its second highest all-time revenue and funds from operations. Over Peyto’s 19 years, the Company has invested $5.7 billion of capital to profitably grow production and reserves per share while generating over $19/share in earnings and paying over $18/share in distributions and dividends. With average Return on Capital Employed (“ROCE”) of 16% and Return on Equity (“ROE”) of 30%, Peyto has been one of Canada’s most profitable natural gas producers. Highlights for the fourth quarter and full year 2017 included:

  • Production per share up 4% Average annual production increased 6%, or 4% per share, to 616 MMcfe/d (102,614 boe/d) in 2017 up from 582 MMcfe/d (96,975 boe/d) in 2016. Q4 2017 production was up 8%, also 8% per share, from Q4 2016 to 659 MMcfe/d (109,793 boe/d). Production deferrals due to low gas price in Q3 and Q4 reduced 2017 annual production by 950 boe/d.
  • Reserves per share up 9% – Producing reserves increased 11% to 1.6 TCFe (275 mmboes), up 9% per share, while total P+P reserves increased 10% to 4.3 TCFe (722 mmboes), up 9% per share.
  • Total Cash costs $0.83/Mcfe ($4.99/boe) – Cash costs of $0.68Mcfe, before royalties of $0.15/Mcfe, included operating costs of $0.27/Mcfe, transportation of $0.16/Mcfe, G&A of $0.04/Mcfe and interest expense of $0.21/Mcfe. Total cash costs in 2017 were up 8% from 2016 due to higher royalties and interest rates. Total 2017 cash costs combined with a realized price of $3.38/Mcfe ($20.32/boe), resulting in a cash netback of $2.55/Mcfe ($15.32/boe) or a 75% operating margin. Q4 2017 cash costs were $0.83/Mcfe ($4.96/boe), with a realized price of $3.50/Mcfe ($20.97/boe) and cash netback of $2.67/Mcfe ($16.01/boe).
  • Funds from operations(3) per share of $3.48 – Annual Funds from Operations (“FFO”) of $574 million, or $3.48/share, was up 11% (10% per share) from $515 million in 2016 as a result of a 6% increase in production combined with a 7% increase in realized commodity prices. Q4 2017 FFO was $162 million or $0.98/share compared to $145 million, or $0.88/share, in Q4 2016.
  • Capital investments of $521 million – A total of $521 million was invested in the drilling of 142 gross (138 net) wells that contributed 47,000 boe/d of incremental production at year end for a cost of $11,000/boe/d. This was consistent with 2016 and is inclusive of $78 million of land, seismic, facility costs and $443 million of well-related costs.
  • PDP FD&A lowest since 2003 – All in cost to develop new producing reserves was $1.36/Mcfe ($8.13/boe), down 6% from 2016, while the field netback for 2017 averaged $2.55/Mcfe ($15.32/boe) resulting in a recycle ratio of 1.9 times. The Company replaced 171% of production with new producing reserves at the lowest cost since 2003.
  • Earnings per share of $1.07 – Annual earnings of $177 million in 2017 were up 57% (55% per share) from $112 million in 2016 due to the increase in cashflow combined with reduced finding costs. Q4 2017 earnings of $52 million ($0.31/share) equated to a profit margin of 24% of revenue. Earnings generated in 2017 represent the 18th consecutive year of recorded profits totaling over $2.33 billion, while cumulative dividends/distributions to shareholders have totaled $2.29 billion.

2017 in Review

The year 2017 was a year of even greater gas price volatility than 2016. Daily Alberta natural gas prices swung wildly from highs of over $4/GJ to, at times, less than zero. The price at which gas could be sold into the future fell by as much as 50%. Much of this volatility was due to a surprising change in NGTL’s service priorities in combination with a late surge of WCSB supply without incremental capacity to access export markets. This has created significant near-term uncertainty for the future of gas prices in the WCSB. Peyto’s hedging practice of forward selling large portions of its natural gas in order to smooth out gas price volatility allowed the Company to continue with mostly steady production operations and to conduct its most active year ever, drilling a record 142 horizontal wells in its liquids-rich, gas resource plays. Several large pipeline projects were completed in the year which expanded Peyto’s owned and operated infrastructure including main gas gathering lines in Brazeau and Whitehorse as well as an integrated liquids storage and gathering pipeline which connected four of the six Greater Sundance gas plants. This liquids pipeline resulted in significantly less trucking which reduced emissions, improved NGL price realizations, and contributed to the 18% annual increase in liquids pricing. Peyto added 88 sections of new land in 2017, almost twice that acquired in 2016, for an average of $253/acre. Although, the Company internally identifies numerous locations per new section of land acquired, these locations have yet to be recognized in the annual reserves evaluation. The solid returns generated on the 2017 capital program drove an 8% ROCE, 11% ROE and 55% increase in earnings per share.

Three Months Ended Dec 31%Twelve Months Ended Dec 31%
Natural gas (mcf/d)595,885556,9757%559,663537,1114%
Oil & NGLs (bbl/d)10,4798,93817%9,3377,45725%
Thousand cubic feet equivalent (Mcfe/d @ 1:6)658,759610,6028%615,684581,8526%
Barrels of oil equivalent (boe/d @ 6:1)109,793101,7678%102,61496,9756%
Production per million common shares (boe/d)*6666188%6225974%
Product prices
Natural gas ($/mcf)2.872.98-4%2.892.89-
Oil & NGLs ($/bbl)56.5245.0925%50.0240.3024%
Operating expenses ($/Mcfe)0.280.268%0.270.258%
Transportation ($/Mcfe)0.160.16- 0.160.16-
Field netback ($/Mcfe)2.912.785%2.802.646%
General & administrative expenses ($/Mcfe)0.030.03- 0.040.04-
Interest expense ($/Mcfe)0.210.1817%0.210.1817%
Financial ($000, except per share*)
Funds from operations161,672144,59312%573,721514,59311%
Funds from operations per share0.980.8811%3.483.1710%
Total dividends54,40854,328- 217,612214,9111%
Total dividends per share0.330.33- 1.321.32-
Payout ratio (%)3438-11%3842-10%
Earnings per share0.310.2334%1.070.6955%
Capital expenditures134,411129,4074%521,210469,37511%
Weighted average common shares outstanding164,874,175164,630,168- 164,856,042162,573,5151%
As at December 31
End of period shares outstanding (includes shares to be issued) 164,874,175164,776,923-
Net debt 1,327,4401,131,05217%
Shareholders' equity 1,722,9781,540,93412%
Total assets 3,844,7143,463,08911%
*all per share amounts using weighted average common shares outstanding

Three Months Ended Dec 31Twelve Months Ended Dec 31
($000 except per share)2017 2016 20172016
Cash flows from operating activities143,568 138,329 535,344508,629
Change in non-cash working capital6,444 (4,012)20,381(24,661)
Change in provision for performance based compensation(4,024)(15,494)2,3124,855
Performance based compensation15,684 25,770 15,68425,770
Funds from operations161,672 144,593 573,721514,593
Funds from operations per share0.98 0.88 3.483.17

(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) Funds from operations - Management uses funds from operations to analyze the operating performance of its energy assets. In order to facilitate comparative analysis, funds from operations is defined throughout this report as earnings before performance based compensation, non‑cash and non‑recurring expenses. Management believes that funds from operations is an important parameter to measure the value of an asset when combined with reserve life. Funds from operations is not a measure recognized by Canadian generally accepted accounting principles ("GAAP") and does not have a standardized meaning prescribed by GAAP. Therefore, funds from operations, as defined by Peyto, may not be comparable to similar measures presented by other issuers, and investors are cautioned that funds from operations should not be construed as an alternative to net earnings, cash flow from operating activities or other measures of financial performance calculated in accordance with GAAP. Funds from operations cannot be assured and future dividends may vary.

The Peyto Strategy

For the past 19 years, the Peyto strategy has focused on maximizing the returns on shareholders’ capital by deploying that capital into the profitable development of long life, low cost, and low risk natural gas resource plays. This strategy of maximizing returns does not end in the field with just the efficient execution of exploration and production operations but continues on to the head office where the management of corporate costs, including the cost of capital, must be controlled to ensure true returns are ultimately enjoyed. Alignment of goals between what is good for the company and its employees and what is good for all stakeholders is critical to ensuring that the greatest returns are achieved. Evidence of the success Peyto has had deploying this strategy, through the commodity price cycle, is illustrated in the following table.

($/Mcfe) 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 19 Year
Sales Price$8.93 $9.54 $6.75 $6.15 $5.47 $4.21 $4.43 $5.04 $3.83 $3.18 $3.38 $4.99
All cash costs but royalties2($1.19)($1.19)($1.12)($0.99)($0.82)($0.73)($0.75)($0.71)($0.67)($0.63)($0.68) ($0.74)
Capital costs1($2.11)($2.88)($2.26)($2.10)($2.12)($2.22)($2.35)($2.25)($1.64)($1.44)($1.36) ($1.83)
Profits$5.63 $5.47 $3.37 $3.06 $2.53 $1.26 $1.33 $2.08 $1.52 $1.12 $1.34 $2.42
63% 57% 50% 50% 46% 30% 30% 41% 40% 35% 40% 49%
Royalty Owners$1.56 $1.82 $0.63 $0.64 $0.53 $0.32 $0.31 $0.37 $0.14 $0.13 $0.15 $0.56
Shareholders $4.07 $3.65 $2.74 $2.42 $2.00 $0.94 $1.02 $1.71 $1.38 $0.99 $1.19 $1.86
Div./Dist. paid $3.92 $4.25 $4.03 $3.37 $1.24 $1.04 $1.01 $1.05 $1.11 $1.01 $0.97 $1.55

1. Capital costs to develop new producing reserves is the PDP FD&A
2. Cash costs not including royalties but including Operating costs, Transportation, G&A and Interest.

The consistency and repeatability of Peyto’s operational execution in the field, combined with strict cost control in all aspects of its business has resulted in nearly 50% of the average sales price being retained in profit. This healthy margin of profit (as defined above), which benefits both royalty owners and shareholders, has been preserved despite a greater than 60% drop in commodity prices from a decade ago. Out of that profit, royalty owners have received approximately 25%, while shareholders, whose capital has been at risk, have received the balance. This margin is what has and will continue to help insulate Peyto and its stakeholders from future volatility in commodity prices.

Capital Expenditures

Peyto drilled 135 gross (131 net) horizontal and 7 gross (7 net) vertical wells in 2017 for a capital investment of $257 million. The Company completed 142 gross (138 net) wells for $134 million and invested $53 million in the wellsite equipment and pipeline connections to bring these wells on production. Both drilling and completion costs on a per-well and per-meter basis were higher than the previous year mostly due to a greater percentage of wells being located in Brazeau, which has less surface infrastructure (roads and existing padsites) already in place. An average of 12.2 frac stages were pumped per well, up from 10.8 stages in 2016, contributing to the higher completion cost per meter.

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

2010 2011 2012 2013 2014 2015 2016 2017
Gross Spuds 52 70 86 99 123 140 126 135
Length (m) 3,762 3,903 4,017 4,179 4,251 4,309 4,197 4,229
Drilling ($MM)$2.763$2.823$2.789$2.720$2.660$2,159$1,818$1,902
$ per meter$734 $723 $694 $651 $626 $501$433$450
Completion ($MM)$1.358$1.676$1.672$1.625$1.693$1,212$857$992
$ per meter$ 361 $ 429 $ 416 $ 389 $ 398 $281$204$235

The Company also invested $57 million into expanding its gas gathering, liquids handling and processing capabilities in the Greater Sundance, Brazeau and the newly established Whitehorse core areas. The most notable was the $23 million, integrated liquids storage and gathering pipeline, which connected four of the six Greater Sundance gas plants and eliminated the need to truck liquids from various plant sites, resulting in greater price realizations going forward for the NGLs produced at those plants. In addition, group pipelines in the Brazeau, Whitehorse and Swanson areas and additional compression at the Brazeau gas plant accounted for the remaining infrastructure investments.

Peyto was successful in acquiring 88 sections of new land in 2017, almost double that of 2016, with 64 sections purchased at Crown sales and 24 purchased through acquisition from other operators. The average cost for both types of land purchases was $253/acre. The majority of lands were purchased in the Brazeau area with some minor lands acquired in the Whitehorse and Sundance areas.

The following table summarizes the capital investments for the fourth quarter and 2017 fiscal year.

Three Months ended December 31Twelve months ended December 31
($000)20172016 2017 2016
Land3,609204 10,328 1,207
Seismic2703,595 6,007 8,149
Drilling 68,90963,130 256,932 219,784
Completions42,12437,256 133,732 105,344
Equipping & Tie-ins15,69514,212 53,146 41,451
Facilities & Pipelines3,61010,955 57,284 60,159
Acquisitions194386 3,823 33,026
Dispositions-(228)(42 )(255)
Leasehold Improvements- (103)- 510
Total Capital Expenditures134,411129,407 521,210 469,375


Peyto was successful in growing reserves per share in all categories in 2017, despite the year over year reduction in commodity price forecasts used by the independent engineering consultants. 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, debt
2017 2016 % Change adjusted per share
Reserves (BCFe)
Proved Producing 1,647 1,48911% (13%)
Total Proved 2,708 2,42612% (12%)
Proved + Probable Additional 4,330 3,92910% (13%)
Net Present Value ($millions) Discounted at 5%
Proved Producing$3,589 $3,536 2%(6%)
Total Proved$5,065$5,0321%(4%)
Proved + Probable Additional$7,581 $7,755(2%)(6%)

†Per share reserves are adjusted for changes in net debt by converting debt to equity using the Dec 31 share price of $15.03 for 2017 and share price of $33.21 for 2016. 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, 2017. The InSite price forecast is available at For more information on Peyto’s reserves, refer to the Press Release dated February 14, 2018 announcing the Year End Reserve Report which is available on the website at 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 2018.

The negative change in reserves per debt adjusted share, was primarily due to the 55% drop in Peyto share price which was used to convert debt to equity, while the negative change in NPV per share was due to the 18% reduction in forecast commodity prices that were used in the reserves evaluation partly offset by the increase in reserve volume.

Value Reconciliation

In order to measure the success of all of the capital invested in 2017, it is necessary to quantify the total amount of value added during the year and compare that to the total amount of capital invested. At Peyto’s request, the independent engineers have run last year’s 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 2017 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 2017, Peyto’s estimated net debt had increased by 17% or $196 million to $1.327 billion while the number of shares outstanding remained effectively the same at 165 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 $1.174 billion of Proved Producing, $1.650 billion of Total Proven, and $2.088 billion of Proved plus Probable Additional undiscounted reserve value, with $521 million of capital investment, cost reductions and NGL price enhancements. 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 2017, the Proved Producing NPV recycle ratio is 2.3 which 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.

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017Wt.
Capital Investment ($MM)$139$73$261$379$618$578$690$594$469$521
NPV0 Recycle Ratio
Proved Producing 2.1 5.4 3.5 2.4 1.6 1.5 1.5 2.3 2.9 2.32.2
Total Proved 2.5 18.9 6.1 4.7 2.2 2.0 1.7 3.3 4.2 3.23.3
Proved + Probable Additional 2.2 27.1 10.3 6.6 3.2 4.0 2.6

5.0 7.3 4.05.1

*NPV0 (net present value) recycle ratio is calculated by dividing the undiscounted NPV of reserves added in the year by the total capital cost for the period (eg. 2017 Proved Producing ($1,176/$521) = 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.

2017 2016 2015 2014 2013 2012 2011 2010 2009
Proved Producing
FD&A ($/Mcfe)$1.36 $1.44 $1.64 $2.25 $2.35 $2.22 $2.12 $2.10 $2.26
RLI (yrs) 7 7 7 7 7 9 9 11 14
Recycle Ratio 2.1 1.8 2.0 1.9 1.6 1.6 2.1 2.4 2.5
Reserve Replacement 171% 153% 193% 183% 190% 284% 230% 239% 79%
Total Proved
FD&A ($/Mcfe)$1.39 $1.01 $0.72 $2.37 $2.23 $2.04 $2.13 $2.35 $1.73
RLI (yrs) 11 11 11 11 12 15 16 17 21
Recycle Ratio 2.0 2.6 4.5 1.8 1.6 1.7 2.1 2.1 3.2
Reserve Replacement 225% 183% 188% 254% 230% 414% 452% 456% 422%
Future Development Capital ($ millions)$1,488 $1,305 $1,381 $1,721 $1,406 $1,318 $1,111 $741 $446
Proved plus Probable Additional
FD&A ($/Mcfe)$1.49 $0.62 $0.54 $2.01 $1.86 $1.68 $1.90 $2.19 $1.47
RLI (yrs) 18 18 17 18 19 22 22 25 29
Recycle Ratio 1.9 4.2 6.1 2.1 2.0 2.1 2.4 2.3 3.8
Reserve Replacement 279% 283% 287% 328% 450% 527% 585% 790% 597%
Future Development Capital ($millions)$2,978 $2,563 $2,657 $2,963 $2,550 $2,041 $1,794 $1,310 $672

  • 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 FDC, by the change in the reserves, incorporating revisions and production, for the same period (eg. Total Proved ($521.2+$183.3)/(451.3-404.4+37.5) = $8.35/boe or $1.39/Mcfe).
  • The RLI is calculated by dividing the reserves (in boes) in each category by the annualized Q4 average production rate in boe/year (eg. Proved Producing 274,551/(109.793x365) = 6.9). Peyto believes that the most accurate way to evaluate the current reserve life is by dividing the proved developed producing reserves by the annualized 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 boe, by the FD&A costs for the period (eg. Proved Producing (($16.79)/$8.16=2.1). 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 ((451.3-404.4+37.5)/37.5) = 225%).

Fourth Quarter 2017

In response to the deteriorating AECO natural gas price forecast, Peyto began reducing drilling activity in the later part of the fourth quarter 2017. The quarter began with 9 drilling rigs active but ended with only 5 rigs drilling running, prior to the holiday season shutdown. Completion and tie-in activity remained robust throughout the entire fourth quarter to catch up to any drilled but uncompleted wells. A total of $111 million was invested in the drilling of 29 gross (29 net) horizontal wells and the completion of 45 gross (45 net) horizontal wells. In addition, $16 million was invested in wellsite equipment and tie-ins while $4 million was invested in new facilities and pipelines. Seismic and land acquisitions of $4 million brought total capital investment for the quarter to $134 million.

The majority of the drilling was concentrated in the Brazeau Notikewin play while the remaining focused on the Greater Sundance area Spirit River formations. Three wells were drilled in the newly established Whitehorse area where the Company is developing a trend of liquids rich Wilrich resource, while two step out wells were drilled to test a new Southern Brazeau land block. The formations and locations of the fourth quarter drilling is illustrated in the following table.

Belly River
Notikewin 12 811
Falher 22
Wilrich23153 115
Bluesky 1 1
Total25353 1129

Production in the fourth quarter 2017 averaged 109,793 boe/d, up 8% from 101,767 boe/d in Q4 2016, made up of 596 MMcf/d of natural gas and 10,479 bbl/d of natural gas liquids. During October and December, periods of low AECO gas price prompted Peyto to defer production which reduced fourth quarter average production by 800 boe/d.

Gas plant optimization and a focus on more liquids rich formations resulted in higher liquid yields in Q4 2017 of 17.6 bbl/MMcf, up from 16.0 bbl/MMcf in Q4 2016. Total liquids for the quarter were split 62% pentanes plus condensates, 20% butane, and 18% propane. Across Peyto’s nine gas plants in the Deep Basin, propane and butane recoveries averaged only 20% and 55%, respectively, in Q4 2017. This is out of a theoretical 80% and 97% recovery, respectively, under deeper cutting facilities, which would correspond to 7,800 bbls/d of additional propane and butane.

The Company’s realized price for natural gas in Q4 2017 was $2.15/Mcf, prior to a $0.72/Mcf hedging gain, while its realized liquids price was $56.52/bbl, yielding a combined revenue stream of $3.50/Mcfe. This net sales price was 4% higher than the $3.38/Mcfe realized in Q4 2016. Total cash costs in Q4 2017 were $0.83/Mcfe ($4.96/boe) up from $0.81/Mcfe in Q4 2016 due to increased operating costs from higher property taxes and higher interest rates. This total Q4 2017 cash cost included royalties of $0.15/Mcfe, operating costs of $0.28/Mcfe, transportation of $0.16/Mcfe, G&A of $0.03/Mcfe and interest of $0.21/Mcfe. Peyto generated total funds from operations of $162 million in the quarter, or $2.67/Mcfe, equating to a 76% operating margin. DD&A charges of $1.43/Mcfe, as well as a provision for current and future performance based compensation and income tax, reduced FFO to earnings of $0.85/Mcfe, or a 24% profit margin. Due to Peyto’s low costs, no impairments were recorded in the quarter. Dividends to shareholders totaled $0.90/Mcfe.


Alberta (AECO) daily natural gas price suffered some of the worst volatility in its history in 2017, driven primarily by changing operating strategies by TCPL on its NGTL pipeline system. Daily AECO price traded as high as $4.09/GJ and as low as minus $2.20/GJ in the year. Throughout the year, the price deteriorated from a daily average of $2.56/GJ in the first quarter to $1.46/GJ in the fourth quarter. Fortunately, Peyto’s hedging practice of layering in future sales in the form of fixed price swaps and committing the majority of its gas production to the AECO Monthly price protected against much of this volatility. For 2017, Peyto’s total natural gas revenues of $590.5 million, were comprised of $523.3 million of pre-sold or hedged gas production (89% of gas revenues) at an average price of $2.58/GJ ($2.97/mcf) and $67.2 million of unhedged, revenue at an average price of $2.28/GJ ($2.62/mcf), prior to NGTL fuel charges. This resulted in a blended realized natural gas price of $2.51/GJ ($2.89/mcf). Peyto’s realized commodity prices by component are listed in the following table.

Commodity Prices by Component

Three Months ended December 31Twelve months ended December 31
2017 2016 2017 2016
Natural gas – after hedging ($/mcf)2.872.982.892.89
Natural gas – after hedging ($/GJ)2.502.592.512.51
AECO monthly ($/GJ)1.852.672.301.98
AECO daily ($/GJ)1.552.932.032.05
Oil and natural gas liquids ($/bbl)
Condensate ($/bbl)67.5456.0560.2047.32
Propane ($/bbl)34.9514.5823.168.73
Butane ($/bbl) 34.9428.0231.2721.69
Pentane ($/bbl)70.0859.1162.4850.50
Total Oil and natural gas liquids ($/bbl)56.5245.0950.0240.30
Canadian Light Sweet stream ($/bbl)69.0561.5862.9452.99

Liquids prices are Peyto realized prices in Canadian dollars adjusted for fractionation and transportation
Gas prices are Peyto realized prices in Canadian dollars net of NGTL fuel charges

Peyto also realized $50.02/bbl for its blend of natural gas liquids in the year, which represented 79% of the Canadian Light Sweet oil price. By the fourth quarter of 2017, as a result of the integrated liquids storage and pipeline project, along with new marketing arrangements for its NGLs, Peyto’s realized liquids pricing improved to 82% of the oil price. As illustrated below, the improved realizations of greater than 80% are expected to continue in the future.

($/bbl)Q1 2015Q2 2015Q3 2015Q4 2015Q1 2016Q2 2016Q3 2016Q4 2016Q1 2017Q2 2017Q3 2017Q4 2017
Peyto realized blended oil and NGL price$37.03 $43.54 $41.69 $39.88 $33.60 $41.46 $39.76 $45.09 $48.14 $48.33 $45.92 $56.52
Canadian Light Sweet Stream$52.72 $68.50 $54.70 $52.02 $40.83 $54.70 $54.82 $61.58 $62.19 $61.95 $56.65 $69.02
% of 70% 64% 76% 77% 82% 76% 73% 73% 77% 78% 81% 82%

Peyto has continued its hedging strategy to smooth out the short term fluctuations in the price of natural gas through future sales. This is done by selling a small portion of the total natural gas production (inclusive of Crown Royalty volumes) on the daily and monthly spot markets while the balance 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’s hedging program aims to achieve a fixed price on a descending, graduated schedule of up to 85% of gross production for the immediate summer or winter season and 75%, 65%, 55%, 45% and 30% targets thereafter for the successive following seasons. These fixed prices are achieved through a series of frequent transactions which is similar to “dollar cost averaging” the future gas prices in order to smooth out volatility. Peyto’s new marketing strategy will attempt to secure the hedges at either the AECO hub or NYMEX Henry Hub to diversify its sales between markets.

To date, Peyto has secured the following revenues through future sales at the AECO:

Future Sales Volume and Revenue
Total258,630,000$2.16 $559,835,338

In addition to the AECO market, Peyto has begun to secure exposure of future volumes to the NYMEX Henry Hub with the following volume committed for the periods shown:

Future Sales Volume and Revenue
2019 2,140,000At Market
20202,140,000At Market
20212,140,000At Market
20222,140,000At Market

The AECO gas price strip currently reflects an oversupply of gas in Alberta relative to the limited egress to export markets. However, initiatives by NGTL towards increased pipeline egress are being recognized by the market and a contraction in the basis differential appears to be underway. In addition, industry activity levels have been tempered and production volumes in the Western Canada Sedimentary Basin are expected to decline as the year progresses due to natural decline. This is expected to bring the supply/demand picture more into balance. Early progress has been made on several market diversification initiatives to position Peyto for maximum netback price realization. The Company has secured some Empress delivery capacity in conjunction with the latest NGTL open season, and will utilize this egress capacity as part of its plan to diversify approximately 40% of production to export pricing.

Details of Peyto’s ongoing marketing efforts are available on Peyto’s website at

Activity Update

Consistent with Peyto’s revised budget, the Company has limited drilling activity in the first quarter of 2018. So far in 2018, Peyto has spud 8 gross (7 net) wells and rig released 9 gross (8.6 net) wells including 2 wells which were spud in late 2017. Peyto has completed and brought on 7 gross (7 net) wells while 6 gross (5.4 net) are waiting on completion and connection with on lease tie-ins.

Included in the program to date are 3 gross (1.9 net) Sundance Cardium wells that follow-up up on two wells drilled last year which are exhibiting production performance that ranks among the top 10 of Peyto’s 50 Sundance Cardium horizontal wells drilled since 2009. The recent performance improvement is attributable to continued innovation in Peyto’s completion design which strives to constantly improve returns. While the Company is excited about the improvements this new design brings to the Sundance Cardium resource play, it is still proceeding cautiously, one well at a time, until the repeatability of results of this new design are proven. Peyto’s Cardium resource in the Greater Sundance area contains 40-60 bbls/mmcf of natural gas liquids and is internally estimated to contain 2.4 TCFe of gas in place with only 14% recovered to date on Peyto lands. The Company has plans for a larger 30-40 well Cardium program in the second half of 2018 building on these recent successes.

The Company has also drilled 2 gross (1.6 net) wells in the Whitehorse area targeting the Wilrich where innovative changes to wellbore design has allowed drilling costs to be reduced to $1.3MM per well. This represents a $600k/well (30%) savings over the average of the 6 prior wells drilled in the area and underlines Peyto’s commitment to continued cost improvement. Peyto’s Whitehorse wells yield 30-40 bbls/mmcf of natural gas liquids which is currently processed at a third party facility while awaiting construction of Peyto’s own plant later in 2018.

New Ventures

Given the current natural gas price environment in Canada, Peyto is actively pursuing opportunities to grow the business both laterally and vertically. The Company is looking to expand its Deep Basin core positions, as well as pursue new opportunities outside of its traditional core properties, to laterally expand its future drilling inventory. As well, Peyto is pursuing opportunities to grow vertically by extracting more value from the existing reserves and infrastructure assets. Early design work is underway for another novel, low cost, mid-cut gas plant process expansion that promises to significantly enhance the recovery of propane and heavier constituents in Peyto’s gas streams. Although still in design phase, the Company anticipates commencement of the first of these newly designed “cheap cut” facility expansions in 2019 and then proceeding sequentially through four or more successive plant instalments into 2020. In all cases, these projects will increase liquid recovery levels by an incremental 10 to 15 bbl/MMcf for the existing plant feed streams.

Peyto has also been in discussion to supply meaningful volumes to intra-Alberta industrial consumers. The Company is excited to be part of what appears to be a very bright future for natural gas producers within Alberta as gas-fired electrical power generation continues to take an ever-increasing role in the province’s power needs. Furthermore, new petrochemical projects which require natural gas feedstock are emerging that promise to supply industrial and agricultural needs both within the province and to export markets. Peyto’s core geographical area is just west of Edmonton, Alberta and proximal to major highway, rail and electrical infrastructure which provides Peyto with an inherent advantage in serving many of these growth industries.

2018 Outlook

Peyto has now entered its 20th year of operations in the Western Canadian Sedimentary Basin. Over that time, the Company has grown from a tiny junior to the fifth largest natural gas producer in Canada. That growth has come almost exclusively through the drill bit and has generated some of the highest returns on capital in the industry. Throughout that time, Peyto has remained nimble and dynamic, adjusting its business plans to account for the changing market conditions so as to ensure capital was continuing to deliver the highest returns possible. That’s why Peyto’s strategy is called a “returns focused strategy” because it is the maximization of return on capital invested that defines the business. Going forward that will not change. The Company will continue to look for ways to invest capital in the energy business that yields the highest possible returns. At times those investments might be to develop new reserves, at other times, to extract additional value from existing reserves. Delivering maximum return to shareholders on whatever capital is invested will continue to remain front and center.

Conference Call and Webcast

A conference call will be held with the senior management of Peyto to answer questions with respect to the 2017 fourth quarter and full year financial results on Thursday, March 1st, 2018, at 9:00 a.m. Mountain Standard Time (MST), or 11:00 a.m. Eastern Standard Time (EST). To participate, please call 1-844-492-6041 (North America) or 1-478-219-0837 (International). Shareholders and interested investors are encouraged to ask questions about Peyto and its most recent results. Questions can be submitted to The conference call can also be accessed through the internet at The conference call will be archived on the Peyto Exploration & Development website at

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 and will be filed at SEDAR, at a later date.

Annual General Meeting

Peyto’s Annual General Meeting of Shareholders is scheduled for 3:00 p.m. on Thursday, May 10, 2018 at the Eau Claire Tower, +15 level, 600 – 3rd Avenue SW, Calgary, Alberta. Shareholders are encouraged to visit the Peyto website at where there is a wealth of information designed to inform and educate investors. A monthly President’s Report can also be found on the website which follows the progress of the capital program and the ensuing production growth, along with video and audio commentary from Peyto’s senior management.

Darren Gee
President and CEO
February 28, 2018

Certain information set forth in this document and Management’s Discussion and Analysis, including management's assessment of Peyto’s future plans and operations, capital expenditures and capital efficiencies, contains forward-looking statements. 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 there from. In addition, Peyto is providing future oriented financial information set out in this press release for the purposes of providing clarity with respect to Peyto’s strategic direction and readers are cautioned that this information may not be appropriate for any other purpose. Other than is required pursuant to applicable securities law, Peyto does not undertake to update forward looking statements at any particular time. To provide a single unit of production for analytical purposes, natural gas production and reserves volumes are converted mathematically to equivalent barrels of oil (BOE). Peyto uses the industry-accepted standard conversion of six thousand cubic feet of natural gas to one barrel of oil (6 Mcf = 1 bbl). The 6:1 BOE ratio is based on an energy equivalency conversion method primarily applicable at the burner tip. It does not represent a value equivalency at the wellhead and is not based on current prices. While the BOE ratio is useful for comparative measures and observing trends, it does not accurately reflect individual product values and might be misleading, particularly if used in isolation. As well, given that the value ratio, based on the current price of crude oil to natural gas, is significantly different from the 6:1 energy equivalency ratio, using a 6:1 conversion ratio may be misleading as an indication of value.

Peyto Exploration & Development Corp.
Balance Sheet
(Amounts in $ thousands)

December 31
December 31
Current assets
Cash5,652 2,102
Accounts receivable90,242 94,813
Due from private placement (Note 6)- 4,930
Derivative financial instruments (Note 11)135,017 -
Prepaid expenses12,578 13,385
243,489 115,230
Long-term derivative financial instruments (Note 11)16,233 -
Property, plant and equipment, net (Note 3)3,584,992 3,347,859
3,601,225 3,347,859
3,844,714 3,463,089
Current liabilities
Accounts payable and accrued liabilities132,776 158,173
Dividends payable (Note 6)18,136 18,109
Provision for future performance based compensation (Note 9)9,166 6,854
Derivative financial instruments (Note 11)- 119,280
160,078 302,416
Long-term debt (Note 4)1,285,000 1,070,000
Long-term derivative financial instruments (Note 11)- 31,465
Provision for future performance based compensation (Note 9)- 4,499
Decommissioning provision (Note 5)143,805 127,763
Deferred income taxes (Note 10)532,853 386,012
1,961,658 1,619,739
Shareholders’ capital (Note 6)1,649,537 1,641,982
Shares to be issued (Note 6)- 4,930
Retained earnings (deficit)(40,261)776
Accumulated other comprehensive income (loss) (Note 6)113,702 (106,754)
1,722,978 1,540,934
3,844,714 3,463,089

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
2017 2016
Oil and gas sales 703,013 559,915
Realized gain on hedges (Note 11) 57,943 118,473
Royalties (34,104) (28,330)
Petroleum and natural gas sales, net 726,852 650,058
Operating (Note 7) 60,423 53,231
Transportation 37,640 34,550
General and administrative 8,538 8,304
Market and reserves based bonus (Note 9) 15,684 25,770
Provision for future performance based compensation (2,187) 9,354
Interest (Note 8) 46,530 39,380
Accretion of decommissioning provision (Note 5) 3,105 2,456
Depletion and depreciation (Note 3) 315,314 330,745
Net gain on disposition of assets (Note 3) (79) (7,885)
484,968 495,905
Earnings before taxes 241,884 154,153
Income tax
Deferred income tax expense (Note 10) 65,309 41,805
Earnings for the year 176,575 112,348
Earnings per share (Note 6)
Basic and diluted $ 1.07 $0.69
Weighted average number of common shares outstanding (Note 6)
Basic and diluted 164,856,042 162,573,515

Peyto Exploration & Development Corp.
Statement of Comprehensive (Loss) Income
(Amounts in $ thousands)

Year ended December 31
2017 2016
Earnings for the year 176,575 112,348
Other comprehensive income
Change in unrealized gain (loss) on cash flow hedges 359,938 (95,142)
Deferred tax (expense) recovery (81,539) 57,676
Realized (gain) on cash flow hedges (57,943)(118,473)
Comprehensive Income (Loss) Income 397,031 (43,591)

Peyto Exploration & Development Corp.
Statement of Changes in Equity
(Amounts in $ thousands)

Year ended December 31
2017 2016
Shareholders’ capital, Beginning of Year1,641,982 1,467,264
Equity offering7,574 172,500
Common shares issued by private placement (Note 6)- 7,644
Common shares issuance costs (net of tax)(19)(5,426)
Shareholders’ capital, End of Year 1,649,537 1,641,982
Common shares to be issued, Beginning of Year4,930 3,769
Common shares issued (Note 6) (4,930) (3,769)
Common shares to be issued (Note 6)- 4,930
Common shares to be issued, End of Year- 4,930
Retained earnings, Beginning of Year776 103,339
Earnings for the year176,575 112,348
Dividends (Note 6) (217,612)(214,911)
Retained earnings (deficit), End of Year(40,261)776
Accumulated other comprehensive (loss) income, Beginning of Year(106,754)49,185
Other comprehensive income (loss) 220,456 (155,939)
Accumulated other comprehensive income (loss), End of Year113,702 (106,754)
Total Equity1,722,978 1,540,934

Peyto Exploration & Development Corp.
Statement of Cash Flows
(Amounts in $ thousands)

Year ended December 31
2017 2016
Cash provided by (used in)
Operating activities
Earnings 176,575 112,348
Items not requiring cash:
Deferred income tax 65,309 41,805
Depletion and depreciation 315,314 330,745
Accretion of decommissioning provision 3,105 2,456
Net gain on disposition of assets (79)(7,885)
Long term portion of future performance based compensation (4,499)4,499
Change in non-cash working capital related to operating activities (20,381)24,661
535,344 508,629
Financing activities
Issuance of common shares 7,574 180,144
Issuance costs (26)(7,432)
Cash dividends paid (217,586)(214,287)
Increase (decrease) in bank debt 215,000 (75,000)
Issuance of long term notes - 100,000
4,962 (16,575)
Investing activities
Additions to property, plant and equipment
Change in prepaid capital
Change in non-cash working capital relating to investing activities
Net increase in cash 3,550 2,102
Cash, beginning of year 2,102 -
Cash, end of year 5,652 2,102

The following amounts are included in Cash flows from operating activities:
Cash interest paid 49,020 34,714
Cash taxes paid - -

Peyto Exploration & Development Corp.
Notes to Financial Statements
As at December 31, 2017 and 2016
(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 300, 600 – 3rd Avenue SW, Calgary, Alberta, Canada, T2P 0G5.

These financial statements were approved and authorized for issuance by the Board of Directors of Peyto on February 27, 2018.

2. Basis of presentation

These financial statements (“financial statements”) as at and for the years ended December 31, 2017 and December 31, 2016 represent the Company’s results and financial position in accordance with International Financial Reporting Standards (“IFRS”).

a) Summary of significant accounting policies

The precise determination of many assets and liabilities is dependent upon future events and the preparation of periodic financial statements necessarily involves the use of estimates and approximations. Accordingly, actual results could differ from those estimates. The financial statements have, in management’s opinion, been properly prepared within reasonable limits of materiality and within the framework of the Company’s basis of presentation as disclosed.

b) Significant accounting estimates and judgements
The timely preparation of the financial statements in conformity with IFRS requires that management make estimates and assumptions and use judgment regarding the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur.

Amounts recorded for depreciation, depletion and amortization, decommissioning costs, 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.

c) 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. The impact of the standard has been evaluated and is expected to not have a material impact on the Company’s 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. IFRS 15 provides clarification for recognizing revenue from contracts with customers and establishes a single revenue recognition and measurement framework. The impact of the standard has been evaluated and is expected to have no material impact on the Company’s financial statements. Additional disclosure may be required upon implementation of IFRS 15 in order to provide sufficient information to enable users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from the contracts with customers.

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.

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

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

f) 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.

g) 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.

h) 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.

i) 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.

j) 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.

k) 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.

l) 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 & LiabilitiesCategory
CashFair value through profit or loss
Accounts ReceivableLoans & receivables
Due from Private PlacementLoans & receivables
Accounts Payable and Accrued LiabilitiesOther liabilities
Provision for Future Performance Based CompensationOther liabilities
Dividends PayableOther liabilities
Long Term DebtOther liabilities
Derivative Financial InstrumentsFair 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.

m) 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.

n) 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.

o) Provisions

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.

p) 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.

q) 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.

r) 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.

s) 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.

t) 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.

u) 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.

3. Property, plant and equipment, net

At December 31, 2015 4,416,643
Additions 473,930
Decommissioning provision net additions 6,425
Prepaid capital 4,525
At December 31, 2016 4,901,523
Additions 520,394
Decommissioning provision net additions 12,935
Prepaid capital 18,220
At December 31, 2017 5,453,072
Accumulated depletion and depreciation
At December 31, 2015 (1,226,584)
Depletion and depreciation (327,080)
At December 31, 2016 (1,553,664)
Depletion and depreciation (314,416)
At December 31, 2017 (1,868,080)
Carrying amount at December 31, 2016 3,347,859
Carrying amount at December 31, 2017 3,584,992

The Company closed various asset swap arrangements during the year ended December 31, 2017. For purposes of determining a gain on disposition, the estimated fair value was based on the fair value of the assets received. The Company recorded a gain of $1.6 million for the year ended December 31, 2017 (2016- $12.7 million gain). The gain is offset by a loss relating to 2017 land expiries in the amount of $1.5 million (2016- $4.8 million loss).

During, 2017 Peyto capitalized $7.9 million (2016 - $7.1 million) of general and administrative expense directly attributable to exploration and development activities.

At December 31, 2017, 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, 2017 and 2016. 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, 2017, current commodity prices and a risk adjusted before tax discount rate of 12%.

The benchmark prices used in the Company’s forecast at December 31, 2017 are outlined as follows:

AECO natural gas ($/MMBtu)2.522.933.223.513.753.853.95

Prices subsequent to 2024 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, 2017 and 2016.

4. Long-term debt

December 31, 2017December 31, 2016
Bank credit facility765,000550,000
Senior unsecured notes520,000520,000
Balance, end of the year1,285,0001,070,000

The Company has a syndicated $1.3 billion extendible unsecured revolving credit facility with a stated term date of October 13, 2021. The bank facility is made up of a $40 million working capital sub-tranche and a $1.26 billion production line. The facilities are available on a revolving basis. Borrowings under the facility bear interest at Canadian bank prime or US base rate, or, at Peyto’s option, Canadian dollar bankers’ acceptances or US dollar LIBOR loan rates, plus applicable margin and stamping fees. The total stamping fees range between 50 basis points and 215 basis points on Canadian bank prime and US base rate borrowings and between 150 basis points and 315 basis points on Canadian dollar bankers’ acceptance and US dollar LIBOR borrowings. The undrawn portion of the facility is subject to a standby fee in the range of 30 to 63 basis points.

On April 26, 2016, the amended and restated note purchase and private shelf agreement dated January 3, 2012 and restated as of April 26, 2013 was amended to increase the shelf facility from $150 million to $250 million.

On October 24, 2016 Peyto closed an issuance of CDN $100 million of senior unsecured notes. The notes were issued by way of private placement pursuant to the amended and restated note purchase and private shelf agreement and rank equally with Peyto’s obligations under its bank facility and existing note purchase agreements. The notes have a coupon rate of 3.7% and mature on October 24, 2023. Interest will be paid semi-annually in arrears.

Peyto is in compliance with all financial covenants at December 31, 2017.

Outstanding senior notes are as follows:

Senior Unsecured NotesDate Issued RateMaturity Date
$100 millionJanuary 3, 20124.39%January 3, 2019
$50 millionSeptember 6, 20124.88%September 6, 2022
$120 millionDecember 4, 20134.50%December 4, 2020
$50 millionJuly 3, 20143.79%July 3, 2022
$100 millionMay 1, 20154.26%May 1, 2025
$100 millionOctober 24, 20163.70%October 24, 2023

Peyto’s total borrowing capacity is $1.82 billion and Peyto’s credit facility is $1.3 billion.

The fair value of all senior notes as at December 31, 2017, is $529.0 million compared to a carrying value of $520.0 million.

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.

Total interest expense for 2017 was $46.5 million (2016 - $39.3 million) and the average borrowing rate for 2017 was 3.9% (2016 – 3.7%).

5. 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, 2015118,882
New or increased provisions16,285
Accretion of discount2,456
Change in discount rate and estimates(9,860)
Balance, December 31, 2016127,763
New or increased provisions14,087
Accretion of discount3,105
Change in discount rate and estimates(1,151)
Balance, December 31, 2017143,805

The Company has estimated the net present value of its total decommissioning provision to be $143.8 million as at December 31, 2017 (2016 – $127.8 million) based on a total future undiscounted liability of $289.7 million (2016 – $258.2 million). At December 31, 2017 management estimates that these payments are expected to be made over the next 49 years (2016 – 48 years) with the majority of payments being made in years 2046 to 2067. The Bank of Canada’s long term bond rate of 2.26 per cent (2016 – 2.31 per cent) and an inflation rate of 2.0 per cent (2016 – 2.0 per cent) were used to calculate the present value of the decommissioning provision.

6. Equity

Share capital
Authorized: Unlimited number of voting common shares

Issued and Outstanding

Common Shares (no par value)Number of
Balance, December 31, 2015158,958,2731,467,264
Common shares issued by private placement281,2707,644
Equity offering5,390,625172,500
Common share issuance costs (net of tax)-(5,426)
Balance, December 31, 2016164,630,1681,641,982
Common shares issued by private placement244,0077,574
Common share issuance costs (net of tax)-(19)
Balance, December 31, 2017164,874,1751,649,537

On March 15, 2016, Peyto completed a private placement of 132,240 common shares to employees and consultants for net proceeds of $3.9 million ($29.30 per common share).

On May 18, 2016, Peyto completed a public offering for 5,390,625 common shares at a price of $32.00 per common share, for net proceeds of $165.6 million.

On December 31, 2016, Peyto completed a private placement of 146,755 common shares to employees and consultants for net proceeds of $4.9 million ($33.59 per share). These common shares were issued January 6, 2017.

On March 14, 2017, Peyto completed a private placement of 97,252 common shares to employees and consultants for net proceeds of $2.6 million ($27.19 per common share).

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, 2017 of 164,856,042 (2016 – 162,573,515). There are no dilutive instruments outstanding.

During the year ended December 31, 2017, Peyto declared and paid dividends of $1.32 per common share or $0.11 per common share for the months of January to December 2017 totaling $217.6 million (2016 - $1.32 or $0.11 per common share for the months of January to December totaling $214.9 million).

On January 15, 2018, Peyto declared dividends of $0.06 per common share that were paid on February 15, 2018. On February 15, 2018, Peyto declared dividends of $0.06 per common share to be paid to shareholders of record on February 28, 2018. These dividends will be paid on March 15, 2018.

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.

7. 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
2017 2016
Gross field expenses 72,238 65,984
Cost recoveries related to processing and gathering of partner production (11,815)(12,753)
Total operating expenses 60,423 53,231

8. Finance costs

Years ended December 31
Interest expense 46,53039,380
Accretion of decommissioning provisions 3,1052,456
Total finance costs 49,63541,836

9. 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
Market based compensation 13,86717,020
Reserve based compensation 1,8178,750
Total market and reserves based compensation 15,68425,770

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

December 31
December 31
Share price$33.80 $33.80
Exercise price (net of dividend)$22.77 $22.77
Expected volatility 0% 0%
Option life 1 year 1 - 2 years
Forfeiture rate 3% 5%
Risk-free interest rate 0% 0%

The changes in total rights outstanding and related weighted average exercise prices for the years ended December 31, 2017 and 2016 were as follows:

Rights (number of shares)Weighted Average
Grant Price ($)
Balance, December 31, 20151,004,717 $34.23
Granted3,798,500 $24.09
Paid out(2,265,550)$27.78
Balance, December 31, 20162,523,667 $24.09
Granted3,918,500 $33.64
Paid out(5,166,900)$31.32
Balance, December 31, 20171,257,400 $24.09

Subsequent to December 31, 2017, 3.9 million rights were granted at a price of $14.68 to be valued at the ten day weighted average market price at December 31, 2017 and vesting 1/3 on each of December 31, 2018, December 31, 2019 and December 31, 2020.

10. Income taxes

2017 2016
Earnings before income taxes241,884 154,153
Statutory income tax rate27.00%27.00%
Expected income taxes65,309 41,622
Increase (decrease) in income taxes from:
True-up tax pools- -
Rate change- -
Other- 183
Total income tax expense65,309 41,805
Deferred income tax expense65,309 41,805
Current income tax expense- -
Total income tax expense65,309 41,805
Differences between tax base and reported amounts for depreciable assets(535,809)(474,918)
Derivative financial instruments(40,838)40,701
Share issuance costs2,388 3,545
Future performance based bonuses2,475 2,728
Provision for decommission provision38,827 34,496
Cumulative eligible capital- 5,331
Charitable donations- 62
Tax loss carry-forwards recognized104 2,043
Deferred income taxes(532,853)(386,012)

At December 31, 2017 the Company has tax pools of approximately $1,550.4 million (2016 - $1,579.9 million) available for deduction against future income.

11. 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, 2017.

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, 2017 and 2016, 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, 2017:

Natural Gas
Period Hedged – Monthly Index
TypeDaily VolumePrice
January 1, 2016 to March 31, 2018Fixed Price5,000 GJ$2.54/GJ
April 1, 2016 to March 31, 2018Fixed Price60,000 GJ$2.42/GJ to $2.75/GJ
April 1, 2016 to October 31, 2018Fixed Price35,000 GJ$2.10/GJ to $2.60/GJ
May 1, 2016 to October 31, 2018Fixed Price20,000 GJ$2.20/GJ to $2.35/GJ
July 1, 2016 to October 31, 2018Fixed Price20,000 GJ$2.28/GJ to $2.45/GJ
August 1, 2016 to October 31, 2018Fixed Price25,000 GJ$2.3175/GJ to $2.5525/GJ
November 1, 2016 to March 31, 2018Fixed Price5,000 GJ$2.51/GJ
April 1, 2017 to March 31, 2018Fixed Price110,000 GJ$2.6050/GJ to $3.1075/GJ
April 1, 2017 to October 31, 2018Fixed Price10,000 GJ$2.585/GJ to $2.745/GJ
October 1, 2017 to March 31, 2018Fixed Price25,000 GJ$2.365/GJ- $2.455/GJ
November 1, 2017 to March 31, 2018Fixed Price185,000 GJ$2.285/GJ to $3.27/GJ
November 1, 2017 to October 31, 2018Fixed Price5,000 GJ$2.92/GJ
December 1, 2017 to March 31, 2018Fixed Price45,000 GJ$1.95/GJ to $2.465/GJ
January 1, 2018 to December 31, 2020 Fixed Price20,000 GJ$2.00/GJ to $2.040/GJ
April 1, 2018 to October 31, 2018Fixed Price90,000 GJ$1.59/GJ to $2.565/GJ
April 1, 2018 to March 31, 2019Fixed Price180,000 GJ$1.54/GJ to $2.625/GJ
April 1, 2018 to October 31, 2019Fixed Price5,000 GJ$1.90/GJ
April 1, 2019 to March 31, 2020Fixed Price45,000 GJ$1.60/GJ to $2.50/GJ
November 1, 2019 to March 31, 2020Fixed Price15,000 GJ$2.02/GJ to $2.05/GJ

Natural Gas
Period Hedged – Daily Index
TypeDaily VolumePrice
April 1, 2018 to October 31, 2018Fixed Price15,000 GJ$1.54/GJ to $1.63/GJ
April 1, 2018 to October 31, 2019Fixed Price30,000 GJ$1.50/GJ to $1.67/GJ

As at December 31, 2017, Peyto had committed to the future sale of 217,245,000 gigajoules (GJ) of natural gas at an average price of $2.29 per GJ or $2.63 per mcf. Had these contracts been closed on December 31, 2017, Peyto would have realized a gain in the amount of $151.3 million. If the AECO gas price on December 31, 2017 were to increase by $0.10/GJ, the unrealized loss would decrease by approximately $21.7 million. An opposite change in commodity prices rates would result in an opposite impact on other comprehensive income.

Subsequent to December 31, 2017 Peyto entered into the following contracts:

Natural Gas
Period Hedged – Monthly Index
TypeDaily VolumePrice
April 1, 2018 to October 31, 2018Fixed Price15,000 GJ$1.30/GJ
April 1, 2018 to March 31, 2020Fixed Price10,000 GJ$1.43/GJ to $1.44/GJ
November 1, 2018 to March 31, 2019Fixed Price60,000 GJ$1.75/GJ to $1.9525/GJ
November 1, 2018 to March 31, 2020Fixed Price5,000 GJ$1.5725/GJ
April 1, 2019 to October 31, 2019Fixed Price15,000 GJ$1.30/GJ
April 1, 2019 to March 31, 2020Fixed Price25,000 GJ$1.45/GJ to $1.51/GJ
April 1, 2020 to October 31, 2020Fixed Price15,000 GJ$1.30/GJ

Natural Gas
Period Hedged – Daily Index
TypeDaily VolumePrice
April 1, 2018 to March 31, 2019Fixed Price10,000 GJ$1.40/GJ to $1.53/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, 2017 would decrease by $6.5 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, 2017, approximately 41% was received from three companies (15%,14% and 12%) (December 31, 2016 – 72% was received from five companies (18%, 17%, 14%, 12%, and 11%). Of the Company’s accounts receivable at December 31, 2017, approximately 25% was receivable from two companies (11% and 14%) (December 31, 2016 approximately 70% was receivable from five companies (18%, 15%, 14%, 12% and 11%). 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, 2017:

December 31, 2017
Current (less than 30 days) 87,957
31-60 days 1,859
61-90 days 78
Past due (more than 90 days) 348
Balance, December 31, 2017 90,242

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, 2017, 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, 2017:

< 1
3-5 YearsThereafter
Accounts payable and accrued liabilities132,776---
Dividends payable18,136---
Provision for future market and reserves based bonus9,166---
Long-term debt(1)--765,000-
Unsecured senior notes-100,000220,000200,000

(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
December 31
Equity1,722,978 1,540,934
Long-term debt1,285,000 1,070,000
Working capital deficit (surplus)(83,411)187,186
2,924,567 2,798,120

12. Related party transactions

Certain directors of Peyto are considered to have significant influence over other reporting entities that Peyto engages in 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 or the related entities. The dollar value of the transactions between Peyto and the related reporting entities is summarized below:

Expense Accounts Payable
Year ended December 31 As at December 31

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 $7.2 million in market and reserves based bonus relating to key management personnel for the year 2017 (2016 - $2.0 million in general and administrative and $12.4 million in market and reserves based bonus).

13. 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, 2017:

Interest payments (1)22,08519,89017,69512,29512,29514,350
Transportation commitments39,19934,46724,04920,52220,23859,251
Operating leases2,2422,2422,2422,2422,3179,269
Total 64,80556,59943,98635,05934,85082,870

(1) Fixed interest payments on senior unsecured notes

14. 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 “Poseidon Shareholder Application”). 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. Peyto 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 (the “Poseidon Action”). 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 September 24, 2014 Poseidon amended its claim in the Poseidon Action to add Poseidon’s auditor, KPMG LLP (“KPMG”), as a defendant.

On May 4, 2016, KPMG issued a third party claim in the Poseidon Action against Poseidon’s former officers and directors and Peyto for any liability KPMG is determined to have to Poseidon. Peyto is not required to deliver a defence to this claim at this time.

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 (the “KPMG Poseidon Shareholder KPMG Action”). On July 29, 2014, KPMG LLP filed a statement of defence 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.

15. Subsequent Events

On January 2, 2018, the Company closed an issuance of CDN $100 million of senior unsecured notes. The notes were issued by way of a private placement, pursuant to a note purchase agreement and a note purchase and private shelf agreement and rank equally with Peyto's obligations under its bank facility and existing note purchase agreements. The notes have a coupon rate of 3.95% and mature on January 2, 2028. Interest will be paid semi-annually in arrears. Proceeds from the notes were used to repay a portion of Peyto's outstanding bank debt.


Darren Gee
President and Chief Executive Officer
Tim Louie
Vice President, Land
Scott Robinson
Executive Vice President New Ventures & Director
David Thomas
Vice President, Exploration
Kathy Turgeon
Vice President, Finance and Chief Financial Officer
Jean-Paul Lachance
Vice President, Engineering & COO
Lee Curran
Vice President, Drilling and Completions
Stephen Chetner
Corporate Secretary
Todd Burdick
Vice President, Production

Don Gray, Chairman
Stephen Chetner
Brian Davis
Michael MacBean, Lead Independent Director
Darren Gee
Gregory Fletcher
Scott Robinson

Deloitte LLP

Burnet, Duckworth & Palmer LLP

Bank of Montreal
Bank of Tokyo-Mitsubishi UFJ, Ltd., 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
National Bank
Wells Fargo

Transfer Agent

Head Office
300, 600 – 3 Avenue SW
Calgary, AB
T2P 0G5

Phone: 403.261.6081
Fax: 403.451.4100
Stock Listing Symbol: PEY.TO
Toronto Stock Exchange

Source: Peyto Exploration & Development Corp.