CALGARY, ALBERTA–(Marketwired – March 1, 2017) – Peyto Exploration & Development Corp. (“Peyto” or the “Company”) (TSX:PEY) is pleased to report operating and financial results for the fourth quarter and 2016 fiscal year. A 76% operating margin¹ and 17% profit margin² allowed Peyto to record its 17^th year of consecutive earnings and achieve a 6% return on capital employed and a 7% return on equity in 2016. This level profitability was achieved despite challenging commodity prices that resulted in losses across much of the energy industry. Highlights for the fourth quarter and full year 2016 included:

• Production per share up 10% – Average annual production increased 13%, or 10% per share, to 582 MMCFe/d (96,975 boe/d) in 2016 up from 514 MMCFe/d (85,674 boe/d) in 2015. Q4 2016 production was up 5%, or 1% per share, from Q4 2015 to 611 MMCFe/d (101,767 boe/d), with exit production of 105,000 boe/d.
• Reserves per share up 7% – Producing reserves increased 8% to 1.5 TCFe (248 mmboes), up 5% per share, while total P+P reserves increased 11% to 3.9 TCFe (654 mmboes), up 7% per share.
• Cash costs down 5% – Royalties, operating costs, transportation, G&A and interest expense totaled $0.76/MCFe in 2016 down 5% from $0.81/MCFe in 2015. Total 2016 cash costs were the lowest in the Company’s 18 year history, which combined with a realized price of $3.18/MCFe, resulting in a cash netback of $2.42/MCFe ($14.50/boe) or a 76% operating margin. Q4 2016 cash costs were $0.81/MCFe, up slightly due to increased royalties, with a realized price of $3.38/MCFe and cash netback of $2.57/MCFe ($15.44/boe).
• Funds from operations per share of $3.17 – Annual Funds from Operations (“FFO”) of $515 million, or $3.17/share, were down 9% (12% per share) from $565 million in 2015 as a result of a 17% reduction in realized commodity prices partially offset by a 13% increase in production and a 5% decrease in cash costs. Q4 2016 FFO was $145 million or $0.88/share compared to $151 million, or $0.95/share, in Q4 2015.
• Capital investments of $469 million – A total of $469 million was invested in the drilling of 128 gross (121 net) wells that contributed 43,600 boe/d of incremental production at year end for a cost of $10,800/boe/d. This was the lowest cost to add new production in the Company’s 18 year history and is inclusive of all land, seismic, facilities, acquisitions, dispositions, and all well-related costs.
• PDP FD&A lowest since 2003 – All in cost to develop new producing reserves was $1.44/MCFe ($8.62/boe), down 12% from 2015, while the field netback for 2016 averaged $2.64/MCFe ($15.84/boe) resulting in a recycle ratio of 1.8 times. The Company replaced 153% of production with new producing reserves at the lowest cost since 2003.
• Earnings per share of $0.69 – Annual earnings of $112 million in 2016 were down 19% (21% per share) from $138 million in 2015 due to the drop in realized commodity prices. Q4 2016 earnings of $38 million ($0.23/share) equated to a profit margin of 20% of revenue. Earnings generated in 2016 represent the 17^th consecutive year of recorded profits totaling over $2.14 billion, while cumulative dividends/distributions to shareholders have totaled $2.07 billion.

2016 in Review

The year 2016 was a year of extreme volatility in natural gas prices which required an astute production strategy in order to preserve capital returns for shareholders. Alberta daily natural gas prices which averaged $2.05/GJ for the year, tested a low of $0.38/GJ on May 9 and a high of $3.87/GJ on December 11. In response, Peyto was quick to restrict production during those months when prices were weak and preserve production and reserves for when prices were stronger. This strategy was only possible because Peyto owns, operates and controls all of its production and processing facilities, and remains committed to maximizing profit and returns rather than just focusing on production. The year 2016 also involved a greater proportion of exploration initiatives resulting in several successful and strategic land acquisitions. Over a third of the wells Peyto drilled in 2016, 46 in total, were not recognized in the previous reserve evaluation as they were deemed too exploratory for review or were on exploratory lands acquired throughout the year. These new ventures will seed future development opportunities and be the source of future returns for shareholders. Throughout the year, both capital costs and cash costs were reduced which ensured profit margins and high returns on capital were retained despite the lower commodity prices.

(1) Operating Margin is defined as Funds from Operations divided by Revenue before Royalties but including realized hedging gains (losses).
(2) Profit Margin is defined as Net Earnings for the year divided by Revenue before Royalties but including realized hedging gains (losses).
Natural gas volumes recorded in thousand cubic feet (Mcf) are converted to barrels of oil equivalent (boe) using the ratio of six (6) thousand cubic feet to one (1) barrel of oil (bbl). Natural gas liquids and oil volumes in barrel of oil (bbl) are converted to thousand cubic feet equivalent (Mcfe) using a ratio of one (1) barrel of oil to six (6) thousand cubic feet. This could be misleading if used in isolation as it is based on an energy equivalency conversion method primarily applied at the burner tip and does not represent a value equivalency at the wellhead.

		3 Months Ended December 31		%	12 Months Ended December 31		%
		2016	2015	Change	2016	2015	Change
Operations
Production
	Natural gas (mcf/d)	556,975	540,512	3%	537,111	474,182	13%
	Oil & NGLs (bbl/d)	8,938	6,943	29%	7,457	6,643	12%
	Thousand cubic feet equivalent (mcfe/d @ 1:6)	610,602	582,167	5%	581,852	514,042	13%
Barrels of oil equivalent (boe/d @ 6:1)		101,767	97,028	5%	96,975	85,674	13%
Production per million common shares (boe/d)*		618	610	1%	597	544	10%
Product prices
	Natural gas ($/mcf)	2.98	3.34	-11%	2.89	3.58	-19%
	Oil & NGLs ($/bbl)	45.09	39.88	13%	40.30	40.40	–
Operating expenses ($/mcfe)		0.26	0.25	4%	0.25	0.29	-14%
Transportation ($/mcfe)		0.16	0.16	–	0.16	0.16	–
Field netback ($/mcfe)		2.78	3.04	-9%	2.64	3.24	-19%
General & administrative expenses ($/mcfe)		0.03	0.05	-40%	0.04	0.04	–
Interest expense ($/mcfe)		0.18	0.16	13%	0.18	0.18	–
Financial ($000, except per share*)
Revenue		189,951	191,606	-1%	678,388	717,836	-5%
Royalties		10,089	6,663	51%	28,330	27,019	5%
Funds from operations		144,593	151,123	-4%	514,593	565,473	-9%
Funds from operations per share		0.88	0.95	-7%	3.17	3.59	-12%
Total dividends		54,328	52,456	4%	214,911	208,149	3%
Total dividends per share		0.33	0.33	–	1.32	1.32	–
	Payout ratio	38	35	9%	42	37	14%
Earnings		38,489	43,406	-13%	112,348	137,561	-19%
Earnings per diluted share		0.23	0.27	-15%	0.69	0.87	-21%
Capital expenditures		129,407	162,442	-20%	469,375	593,780	-21%
Weighted average common shares outstanding		164,630,168	158,958,273	4%	162,573,515	157,492,332	3%
As at December 31
End of period shares outstanding (includes shares to be issued					164,776,923	159,107,303	4%
Net debt					1,131,052	1,104,602	2%
Shareholders’ equity					1,540,934	1,623,557	-5%
Total assets					3,463,089	3,357,514	3%
*all per share amounts using weighted average common shares outstanding

		3 Months Ended December 31		12 Months Ended December 31
($000 except per share)		2016	2015	2016	2015
Cash flows from operating activities		138,329	130,483	508,629	530,208
	Change in non-cash working capital	(4,012)	13,168	(24,661)	18,109
	Change in provision for performance based compensation	(15,494)	(15,911)	4,855	(6,227)
Performance based compensation		25,770	23,383	25,770	23,383
Funds from operations		144,593	151,123	514,593	565,473
Funds from operations per share		0.88	0.95	3.17	3.59

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

The Peyto Strategy

For the past 18 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’s had deploying this strategy, through the commodity price cycle, can be seen in the following table.

($/Mcfe)	2006	2007	2008	2009	2010	2011	2012	2013	2014	2015	2016		18 Year Wt. Avg.
Sales Price	$8.76	$8.93	$9.54	$6.75	$6.15	$5.47	$4.21	$4.43	$5.04	$3.83	$3.19		$5.27
All cash costs but royalties2	($0.89)	($1.19)	($1.19)	($1.12)	($0.99)	($0.82)	($0.73)	($0.75)	($0.71)	($0.67)	($0.64)		($0.75)
Capital costs1	($2.95)	($2.11)	($2.88)	($2.26)	($2.10)	($2.12)	($2.22)	($2.35)	($2.25)	($1.64)	($1.44)		($1.90)
Profits	$4.92	$5.63	$5.47	$3.37	$3.06	$2.53	$1.26	$1.33	$2.08	$1.52	$1.12		$2.62
Royalty Owners	($1.77)	($1.56)	($1.82)	($0.63)	($0.64)	($0.53)	($0.32)	($0.31)	($0.37)	($0.14)	($0.13)		($0.63)
Shareholders	($3.15)	($4.07)	($3.65)	($2.74)	($2.42)	($2.00)	($0.94)	($1.02)	($1.71)	($1.38)	($0.99)		($1.99)
Div./Dist. paid	$3.47	$3.92	$4.25	$4.03	$3.37	$1.24	$1.04	$1.01	$1.05	$1.11	$1.01		$1.77

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.

Even though commodity prices have dropped by over 60% from a decade ago, Peyto has maintained a healthy margin of profit (as defined above) to the benefit of both royalty owners and shareholders. On average over the Company’s 18 year history, the consistency and repeatability of Peyto’s execution in the field combined with strict cost control has resulted in nearly 50% of the average sales price being retained in profit. Out of that profit, royalty owners have received approximately 25%, while shareholders, whose capital has been at risk, have received the balance. This level of profitability, in which all stakeholders share, is so high it is unique in the energy industry and continues to differentiate the Peyto team and its strategy.

Capital Expenditures

Peyto drilled 125 gross (118 net) horizontal wells and 3 gross (3 net) vertical wells in 2016, investing $220 million in drilling and $105 million in completions. Both drilling and completion costs on a per-well and per-meter basis were lower than from the previous year due to reduced industry service costs, design changes and improvements in execution. This reduced capital cost helped build new production at the lowest cost in the Company’s history and helped develop new producing reserves at the lowest cost in over a decade. Average horizontal well length decreased slightly to 4,197 m measured depth mainly due to well spacing constraints, while an average of 10.8 frac stages were pumped per well, up from 10.6 stages in 2015. Wellsite equipment and tie-ins accounted for $42 million in the year, or approximately $315,000 per well, as Peyto continued to take advantage of pad drilling and existing infrastructure.

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

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

The Company also invested $60 million into expanding its gas gathering and processing capabilities across Peyto’s core areas. The most notable expansion occurred at the Brazeau gas plant which included a second refrigeration unit and six new compressors taking capacity from 60 MMcf/d to 140 MMcf/d. In addition, a major pipeline project extended the reach of the Brazeau gathering system 13 km to the west of the plant. This new infrastructure enabled production in the area to grow from 10,000 boe/d at the start of 2016 to 19,000 boe/d by year end.

Additional infrastructure investments included projects at Oldman, Swanson as well as general rotating equipment overhauls and engine swaps at all facilities. Modifications to the Oldman Deep Cut process train was made to allow ease of propane recovery in liquid form or rejection into the sales gas stream as changing market conditions dictate. This modification will save both operating costs and fuel gas consumption during periods when propane value may be insufficient to justify recovery.

Peyto was successful in acquiring additional lands in 2016, mostly from other operators in the basin. At Crown sales Peyto acquired 14 sections of new land at an average purchase price of $135 per acre. More significantly, the Company closed seven asset purchases totaling $33 million which included 31.3 net sections of land and 1,300 boe/d of mostly joint interest, Peyto operated production.

The following table summarizes the capital investments for the fourth quarter and 2016 fiscal year.

	Three Months ended December 31		Twelve Months ended December 31
($000)	2016	2015	2016	2015
Land	204	–	1,207	5,451
Seismic	3,595	2,158	8,149	6,530
Drilling	63,130	70,589	219,784	287,560
Completions	37,256	53,881	105,344	173,445
Equipping & Tie-ins	14,212	16,221	41,451	48,716
Facilities & Pipelines	10,955	18,953	60,159	74,417
Acquisitions	386	36	33,026	3,143
Dispositions	(228)	–	(255)	(6,282)
Leasehold Improvements	(103)	604	510	800
Total Capital Expenditures	129,407	162,442	469,375	593,780

Reserves

Peyto was successful in growing reserves in all categories in 2016, 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
	2016	2015	% Change	% Change, debt adjusted per share*
Reserves (BCFe)
Proved Producing	1,489	1,375	8%	10%
Total Proved	2,426	2,249	8%	11%
Proved + Probable Additional	3,929	3,539	11%	14%
Net Present Value ($millions) Discounted at 5%
Proved Producing	$3,536	$3,175	11%	12%
Total Proved	$5,032	$4,354	16%	16%
Proved + Probable Additional	$7,755	$6,450	20%	20%

* Per share reserves are adjusted for changes in net debt by converting debt to equity using the Dec 31 share price of $24.87 for 2015 and share price of $33.21 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, 2016. The InSite price forecast is available at http://www.insitepc.com/. For more information on Peyto’s reserves, refer to the Press Release dated February 14, 2017 announcing the Year End Reserve Report which is available on the website at http://www.peyto.com/. The complete statement of reserves data and required reporting in compliance with NI 51-101 will be included in Peyto’s Annual Information Form to be released in March 2017.

Value Reconciliation

In order to measure the success of all of the capital invested in 2016, 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 2016 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 2016, Peyto’s estimated net debt had increased by 2% or $26.5 million to $1.131 billion while the number of shares outstanding had increased by 4% or 5.67 million shares to 164.777 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 $1.357 billion of Proved Producing, $1.979 billion of Total Proven, and $3.423 billion of Proved plus Probable Additional undiscounted reserve value, with $469 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 2016, the Proved Producing NPV recycle ratio is 2.9. This means for each dollar invested, the Peyto team was able to create 2.9 new dollars of Proved Producing reserve value.

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

Value Creation	31-Dec-07	31-Dec-08	31-Dec-09	31-Dec-10	31-Dec-11	31-Dec-12	31-Dec-13	31-Dec-14	31-Dec-15	31-Dec-16
NPV0 Recycle Ratio
Proved Producing	4.7	2.1	5.4	3.5	2.4	1.6	1.5	1.5	2.3	2.9
Total Proved	5.5	2.5	18.9	6.1	4.7	2.2	2.0	1.7	3.3	4.2
Proved + Probable Additional	3.8	2.2	27.1	10.3	6.6	3.2	4.0	2.6	5.0	7.3

*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. 2016 Proved Producing ($1,357/$469) = 2.9).

Based on this reconciliation of value, the NPV₅ of the Company’s remaining P+P reserves, on a debt adjusted, per share basis, has increased 20% from $33.60 in 2015 to $40.19 in 2016.

PERFORMANCE RATIOS

The following table highlights annual performance ratios since 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.

		2016	2015	2014	2013	2012	2011	2010	2009
Proved Producing
	FD&A ($/MCFe)	$1.44	$1.64	$2.25	$2.35	$2.22	$2.12	$2.10	$2.26
	RLI (yrs)	7	7	7	7	9	9	11	14
	Recycle Ratio	1.8	2.0	1.9	1.6	1.6	1.9	2.0	1.8
	Reserve Replacement	153%	193%	183%	190%	284%	230%	239%	79%
Total Proved
	FD&A ($/MCFe)	$1.01	$0.72	$2.37	$2.23	$2.04	$2.13	$2.35	$1.73
	RLI (yrs)	11	11	11	12	15	16	17	21
	Recycle Ratio	2.6	4.5	1.8	1.6	1.7	1.9	1.8	2.3
	Reserve Replacement	183%	188%	254%	230%	414%	452%	456%	422%
	Future Development Capital ($ millions)	$1,305	$1,381	$1,721	$1,406	$1,318	$1,111	$741	$446
Proved plus Probable Additional
	FD&A ($/MCFe)	$0.62	$0.54	$2.01	$1.86	$1.68	$1.90	$2.19	$1.47
	RLI (yrs)	18	17	18	19	22	22	25	29
	Recycle Ratio	4.2	6.1	2.1	2.0	2.1	2.1	1.9	2.8
	Reserve Replacement	283%	287%	328%	450%	527%	585%	790%	597%
	Future Development Capital ($millions)	$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 ($469.4-$76.2)/(404.4-374.8+35.5) = $6.04/boe or $1.01/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 248,316/(101.767×366) = 6.7). Peyto believes that the most accurate way to evaluate the current reserve life is by dividing the proved developed producing reserves by the actual annualized 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 (($15.84)/$8.62=1.8). 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 ((404.4-374.8+35.5)/35.5) = 183%).

Quarterly Review

Peyto maintained a 9 drilling rig program throughout the fourth quarter 2016 with drilling and completions shutting down for approximately two weeks over the holiday season. Several completions were postponed into the new year due to increased activity and seasonal delays. A total of $100 million was invested in the drilling of 32 gross (29.7 net) horizontal wells and the completion of 39 gross (36 net) horizontal and 2 gross (2 net) vertical wells. In addition, $14 million was invested in wellsite equipment and tie-ins while $11 million was invested in new facilities and pipelines. Seismic and acquisitions (net of dispositions) of $4 million brought total capital investment for the quarter to $129 million.

Two drilling rigs worked in the Ansell area, three in the Brazeau area, and the remaining four rigs were drilling in the greater Sundance area, and all were focused on Spirit River targets in the Notikewin, Falher and Wilrich formations as illustrated in the following table.

	Field							Total Wells Drilled
Zone	Sundance	Nosehill	Wildhay	Ansell/ Minehead	Berland	Kisku/ Kakwa	Brazeau
Cardium
Notikewin	2	1		3			7	13
Falher	2	4	3				1	10
Wilrich		2	1	5			1	9
Bluesky
Total	4	7	4	8			9	32

Production in the fourth quarter 2016 averaged 101,767 boe/d, up 5% from 97,028 in Q4 2015, made up of 557 MMcf/d of natural gas and 8,938 bbl/d of natural gas liquids. During December, Peyto experienced anomalously high sales line pressures on TCPL’s inter-Alberta pipeline system which resulted in approximately 1,500 boe/d of deferred production. Peyto has developed strategies to address ongoing pressure and firm service curtailment issues so that similar future events have less effect on Company production.

Realized propane prices continued to improve during the quarter and Peyto continued to adjust the operating conditions of its refrigeration plant processes to extract more propane from the sales gas stream. As well, Peyto restarted the deep cut process at the Company’s Oldman gas plant. As a result, the propane production in Q4 2016 was 1,463 bbls/d up from 323 bbls/d in Q4 2015. NGL yields averaged 16.0 bbl/mmcf in the fourth quarter, up from 13.6 bbl/mmcf in Q3 2016 and 12.8 bbl/mmcf in the year before due to this increased propane recovery.

The Company’s realized price for natural gas in Q4 2016 was $3.04/Mcf, prior to a $0.06/Mcf hedging loss, while its realized liquids price was $45.09/bbl, yielding a combined revenue stream of $3.38/Mcfe. This net sales price was 6% lower than the $3.58/Mcfe realized in Q4 2015.

Total cash costs in Q4 2016 were $0.81/Mcfe ($4.85/boe) up from $0.76/Mcfe in Q3 2016 due to increased royalties from higher commodity prices. This total included royalties of $0.18/Mcfe, operating costs of $0.26/Mcfe, transportation of $0.16/Mcfe, G&A of $0.03/Mcfe and interest of $0.18/Mcfe.

Peyto generated total funds from operations of $145 million in the quarter, or $2.57/Mcfe, equating to a 76% operating margin. DD&A charges of $1.46/Mcfe, as well as a provision for current and future performance based compensation and income tax, reduced FFO to earnings of $0.69/Mcfe, or a 20% profit margin. Due to Peyto’s low costs, no impairments were recorded in the quarter. Dividends to shareholders totaled $0.97/Mcfe.

Marketing

Alberta (AECO) natural gas prices in 2016 were some of the most volatile in Peyto’s history following a similar path to prices in 2012 when a previously mild winter and robust storage levels pushed summer prices to extreme lows, only to rebound by the following winter. On two separate occasions in the summer of 2016 daily AECO natural gas price traded below $0.50/GJ but by the end of the year the price traded as high as $3.87/GJ. On average for 2016, Peyto realized a natural gas price of $2.51/GJ or $2.89/Mcf. This was the result of a combination of approximately 26% being sold in the daily or monthly spot market at an average of $1.82/GJ and 74% having been pre-sold at an average hedged price of $2.74/GJ. In the fourth quarter, this combination was 11% in the spot market at $2.64/GJ and 89% pre-sold at an average hedged price of $2.57/GJ to yield a total realized price of $2.59/GJ (all prices reported net of TCPL fuel charges).

Peyto also realized $40.30/bbl for its blend of natural gas liquids in the year, which represented 76% of the Canadian Light Sweet oil price. In the fourth quarter of 2016 Peyto was fully recovering propane again with its Oldman deep cut process in operation. As illustrated below, the realized propane price in Q4 2016 was up to 24% of Canadian Light Sweet oil price.

Commodity Prices by Component

		Three Months ended December 31		Twelve Months ended December 31
		2016	2015	2016	2015
Natural gas – after hedging ($/mcf)		2.98	3.34	2.89	3.58
Natural gas – after hedging ($/GJ)		2.59	2.90	2.51	3.12
AECO monthly ($/GJ)		2.67	2.51	1.98	2.62
Oil and natural gas liquids ($/bbl)
	Condensate ($/bbl)	56.05	45.29	47.32	51.09
	Propane ($/bbl)	14.58	(4.82)	8.73	(1.99)
	Butane ($/bbl)	28.02	22.47	21.69	23.55
	Pentane ($/bbl)	59.11	49.05	50.50	51.79
Total Oil and natural gas liquids ($/bbl)		45.09	39.88	40.30	40.40
Cdn Light Sweet stream ($/bbl)		61.58	52.95	52.99	57.21

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

To prevent the short term volatility in natural gas prices from interfering with capital planning, Peyto uses a hedging strategy that is designed to smooth out the short term fluctuations in the price of natural gas through future sales. This is done by selling 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. At present, Peyto has approximately 75% of total forecast 2017 natural gas production pre-sold at an average price of $2.95/mcf.

The following table summarizes the remaining hedged volumes for the upcoming years effective March 1, 2017:

	Future Sales			Average Price (CAD)
	GJ	Mcf*	$/GJ	$/Mcf*
2017	144,960,000	126,052,174	2.59	2.98
2018	84,805,000	73,743,478	2.55	2.94
2019	7,700,000	6,695,652	2.51	2.89
2020	910,000	791,304	2.47	2.84
Total	238,375,000	207,282,609	2.58	2.96

*Assuming historical heat content

In order to deal with restricted access to take-away capacity, Peyto has arranged for excess firm transportation on the Nova Gas Transmission Ltd. (“NGTL”) system north of the James River receipt point which varies between 108% and 123% of Peyto’s forecasted natural gas sales for the year. Specific monthly excess service is projected to offset the outage forecast provided by NGTL.

Activity Update

Peyto began 2017 with 9 drilling rigs active, 4 in the Brazeau area and 5 in the greater Sundance area. Their startup in January after shutting down over the holiday break was staggered to accommodate pressure pumping availability. To date, a total of 32 gross (30.8 net) wells have been spud with 23 gross (21.8 net) wells rig released. Peyto has completed and brought on production 18 gross (17.2 net) wells including wells drilled in late 2016 and has another 17 gross (15.8 net) wells in the process of being completed and or tied-in. Peyto plans to run 4 rigs through breakup this year in the greater Sundance area by using pad drilling in locations where it is less likely to experience a cost premium for unpredictable weather conditions.

New well conversions have been slower to materialize as Peyto continues to focus on keeping costs down with 4 rigs working on pad locations. Production to date has averaged approximately 101,000 boe/d with 4,000 boe/d tested and waiting on pipelines in the short term and an additional 3,000 boe/d waiting on longer term facility plans. High line pressures on the TCPL system have created some challenges so far this year but restrictions on the mainline due to TCPL service outages have been effectively mitigated with Peyto’s excess firm service contracts.

Peyto has started a liquids pipeline project in the greater Sundance area that will interconnect four major gas plants (Oldman, Oldman North, Nosehill and Swanson) for more efficient and cost effective transport of two main liquids products; the segregated condensate and the natural gas liquids mix. By eliminating the inter-plant trucking of these products Peyto will reduce the associated greenhouse gas emissions and risk of a spill that is inherent to trucking products. The project is estimated to cost approximately $15 million and will reduce annual transportation costs by $5 million per year which Peyto will realize through increased liquids prices of approximately $2.50/bbl. The pipeline installation is 65% constructed and is progressing towards an April 2017 completion.

Equipment is ready for the next major phase of infrastructure expansion in the Brazeau area with approximately 70 MMcf/d of equipment capacity ready to install. TCPL will also be expanding their meter station this spring, coinciding with this infrastructure expansion, which will increase total Brazeau take away capacity to 210 MMfc/d by mid-year.

Peyto has successful added 21,120 acres (33 net sections) of exploratory land at Crown sales so far in 2017. Average purchase price for this new land was $225/acre. The Company has also completed the shooting of 118 square miles of 3D seismic that was started in the December of 2016 that extends total seismic coverage in the Brazeau area.

2017 Outlook

The outlook for 2017 is one of renewed optimism as the Company looks to deploy a larger capital program but with the same costs and efficiencies enjoyed last year. Strategic alliances with certain service providers will be key in achieving this goal. Commodity prices, especially AECO natural gas prices have recently retreated on lack of winter weather and renewed over supply concerns. As a result, Peyto remains guarded with respect to current industry activity levels and potential service cost inflation. As well, ongoing take-away capacity issues on TCPL’s inter-Alberta system has required Peyto to put in place a strategy of increased transportation and hedging to ensure new production can be produced and sold at prices that generate sufficient return for shareholders. As always, the focus on maximizing the return on the capital invested remains paramount.

Longer term, Peyto continues to focus on the Alberta Deep Basin for its new opportunities. The resource plays within the basin are situated in an advantageous position relative to the existing constricted take away capacity. With current costs and current commodity prices, Management is confident above average returns can continue to be generated and realized as future dividends to shareholders. Peyto has a wealth of existing development opportunities in inventory that it will continue to harvest as well as almost two decades of experience finding additional opportunities.

Conference Call and Webcast

A conference call will be held with the senior management of Peyto to answer questions with respect to the 2016 fourth quarter and full year financial results on Thursday, March 2nd, 2017, 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 [email protected]. The conference call can also be accessed through the internet at http://edge.media-server.com/m/p/tzgb3xgg . The conference call will be archived on the Peyto Exploration & Development website at www.peyto.com.

Management’s Discussion and Analysis

A copy of the fourth quarter report to shareholders, including the MD&A, audited financial statements and related notes, is available at http://www.peyto.com/news/Q42016MDandA.pdf and will be filed at SEDAR, www.sedar.com at a later date.

Annual General Meeting

Peyto’s Annual General Meeting of Shareholders is scheduled for 3:00 p.m. on Wednesday, May 11, 2017 at the Telus Convention Centre, Glen 206 Ballroom, 120 – 9^th Avenue SE, Calgary, Alberta. Shareholders are encouraged to visit the Peyto website at www.peyto.com where there is a wealth of information designed to inform and educate investors. A monthly President’s Report can also be found on the website which follows the progress of the capital program and the ensuing production growth, along with video and audio commentary from Peyto’s senior management.

Darren Gee
President and CEO
March 1, 2017

Certain information set forth in this document and Management’s Discussion and Analysis, including management’s assessment of Peyto’s future plans and operations, contains forward-looking statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: the timing of its enhanced liquids extraction project and guidance as to the capital expenditure plans of Peyto under the heading “2017 Outlook”. By their nature, forward-looking statements are subject to numerous risks and uncertainties, some of which are beyond these parties’ control, including the impact of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility and ability to access sufficient capital from internal and external sources. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Peyto’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits Peyto will derive therefrom.

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

	December 31 2016	December 31 2015
Assets
Current assets
Cash	2,102	–
Accounts receivable	94,813	85,525
Due from private placement (Note 6)	4,930	3,769
Derivative financial instruments (Note 11)	–	65,169
Prepaid expenses	13,385	12,992
	115,230	167,455
Property, plant and equipment, net (Note 3)	3,347,859	3,190,059
	3,347,859	3,190,059
	3,463,089	3,357,514
Liabilities
Current liabilities
Accounts payable and accrued liabilities	158,173	144,402
Dividends payable (Note 6)	18,109	17,486
Provision for future performance based compensation (Note 9)	6,854	1,998
Derivative financial instruments (Note 11)	119,280	–
	302,416	163,886
Long-term debt (Note 4)	1,070,000	1,045,000
Long-term derivative financial instruments (Note 11)	31,465	2,299
Provision for future performance based compensation (Note 9)	4,499	–
Decommissioning provision (Note 5)	127,763	118,882
Deferred income taxes (Note 10)	386,012	403,890
	1,619,739	1,570,071
Equity
Shareholders’ capital (Note 6)	1,641,982	1,467,264
Shares to be issued (Note 6)	4,930	3,769
Retained earnings	776	103,339
Accumulated other comprehensive income (Note 6)	(106,754)	49,185
	1,540,934	1,623,557
	3,463,089	3,357,514

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
	2016	2015
Revenue
Oil and gas sales	559,915	609,274
Realized gain on hedges (Note 11)	118,473	108,562
Royalties	(28,330)	(27,019)
Petroleum and natural gas sales, net	650,058	690,817
Expenses
Operating (Note 7)	53,231	54,121
Transportation	34,550	28,996
General and administrative	8,304	7,105
Market and reserves based bonus (Note 9)	25,770	23,383
Provision for future performance based compensation (Note 9)	9,354	(7,251)
Interest (Note 8)	39,380	35,122
Accretion of decommissioning provision (Note 5)	2,456	2,400
Depletion and depreciation (Note 3)	330,745	325,528
Net gain on disposition of assets (Note 3)	(7,885)	(2,575)
	495,905	466,829
Earnings before taxes	154,153	223,988
Income tax
Deferred income tax expense (Note 10)	41,805	86,427
Earnings for the year	112,348	137,561
Earnings per share (Note 6)
Basic and diluted	$ 0.69	$ 0.87
Weighted average number of common shares outstanding (Note 6)
Basic and diluted	162,573,515	157,492,332

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

	Year ended December 31
	2016	2015
Earnings for the year	112,348	137,561
Other comprehensive income
Change in unrealized (loss) gain on cash flow hedges	(95,142)	66,369
Deferred tax recovery	57,676	11,392
Realized (gain) on cash flow hedges	(118,473)	(108,562)
Comprehensive (Loss) Income	(43,591)	106,760

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

	Year ended December 31
	2016	2015
Shareholders’ capital, Beginning of Year	1,467,264	1,292,398
Equity offering	172,500	172,517
Common shares issued by private placement (Note 6)	7,644	7,732
Common shares issuance costs (net of tax)	(5,426)	(5,383)
Shareholders’ capital, End of Year	1,641,982	1,467,264
Common shares to be issued, Beginning of Year	3,769	5,625
Common shares issued (Note 6)	(3,769)	(5,625)
Common shares to be issued (Note 6)	4,930	3,769
Common shares to be issued, End of Year	4,930	3,769
Retained earnings, Beginning of Year	103,339	173,927
Earnings for the year	112,348	137,561
Dividends (Note 6)	(214,911)	(208,149)
Retained earnings, End of Year	776	103,339
Accumulated other comprehensive income, Beginning of Year	49,185	79,986
Other comprehensive (loss)	(155,939)	(30,801)
Accumulated other comprehensive income, End of Year	(106,754)	49,185
Total Equity	1,540,934	1,623,557

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

		Year ended December 31
		2016	2015
Cash provided by (used in)
Operating activities
Earnings		112,348	137,561
Items not requiring cash:
	Deferred income tax	41,805	86,427
	Depletion and depreciation	330,745	325,528
	Accretion of decommissioning provision	2,456	2,400
	Net gain on disposition of assets	(7,885)	(2,575)
	Long term portion of future performance based compensation	4,499	(1,024)
Change in non-cash working capital related to operating activities		24,661	(18,109)
		508,629	530,208
Financing activities
Issuance of common shares		180,144	180,249
Issuance costs		(7,432)	(7,374)
Cash dividends paid		(214,287)	(207,570)
(Decrease) Increase in bank debt		(75,000)	20,000
Issuance of long term notes		100,000	100,000
		(16,575)	85,305
Investing activities
Additions to property, plant and equipmentChange in prepaid capitalChange in non-cash working capital relating to investing activities		(469,375) (4,525) (16,052)	(593,780) (6,274) (15,459)
		(489,952)	(615,513)
Net increase in cash		2,102	–
Cash, beginning of year		–	–
Cash, end of year		2,102	–
The following amounts are included in Cash flows from operating activities:
Cash interest paid		34,714	37,962
Cash taxes paid		–	–

Peyto Exploration & Development Corp.
Notes to Financial Statements
As at December 31, 2016 and 2015
(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 – 3^rd 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 28, 2017.

2. Basis of presentation

These financial statements (“financial statements”) as at and for the years ended December 31, 2016 and December 31, 2015 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 and the Company is currently evaluating the impact of the standard on its financial statements.

In May 2014, the IASB issued IFRS 15 “Revenue from Contracts with Customers,” which replaces IAS 18 “Revenue,” IAS 11 “Construction Contracts,” and related interpretations. The standard is required to be adopted for fiscal years beginning on or after January 1, 2018, with earlier adoption permitted. IFRS 15 will be applied by Peyto on January 1, 2018 and the Company is currently evaluating the impact of the standard on Peyto’s financial statements.

In January 2016, the IASB issued IFRS 16 “Leases”, which replaces IAS 17 “Leases”. For lessees applying IFRS 16,
a single recognition and measurement model for leases would apply, with required recognition of assets and liabilities for most leases. The standard will come into effect for annual periods beginning on or after January 1, 2019, with earlier adoption permitted. The Company is currently evaluating the impact of the standard on the Company’s financial statements.

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

Derivative instruments and risk management

Derivative instruments are utilized by the Company to manage market risk against volatility in commodity prices. The Company’s policy is not to utilize derivative instruments for speculative purposes. The Company has chosen to designate its existing derivative instruments as cash flow hedges. The Company assesses, on an ongoing basis, whether the derivatives that are used as cash flow hedges are highly effective in offsetting changes in cash flows of hedged items. All derivative instruments are recorded on the balance sheet at their fair value. The effective portion of the gains and losses is recorded in other comprehensive income until the hedged transaction is recognized in earnings. When the earnings impact of the underlying hedged transaction is recognized in the income statement, the fair value of the associated cash flow hedge is reclassified from other comprehensive income into earnings. Any hedge ineffectiveness is immediately recognized in earnings. The fair values of forward contracts are based on forward market prices.

Embedded derivatives

An embedded derivative is a component of a contract that causes some of the cash flows of the combined instrument to vary in a way similar to a stand-alone derivative. This causes some or all of the cash flows that otherwise would be required by the contract to be modified according to a specified variable, such as interest rate, financial instrument price, commodity price, foreign exchange rate, a credit rating or credit index, or other variables to be treated as a financial derivative. The Company has no contracts containing embedded derivatives.

Normal purchase or sale exemption

Contracts that were entered into and continue to be held for the purpose of the receipt or delivery of a non-financial item in accordance with the Company’s expected purchase, sale or usage requirements fall within the exemption from IAS 32 Financial Instruments: Presentation (“IAS 32”) and IAS 39, which is known as the ‘normal purchase or sale exemption’. The Company recognizes such contracts in its balance sheet only when one of the parties meets its obligation under the contract to deliver either cash or a non-financial asset.

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

General

Provisions are recognized when the Company has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where the Company expects some or all of a provision to be reimbursed, the reimbursement is recognized as a separate asset but only when the reimbursement is virtually certain. The expense relating to any provision is presented in the income statement net of any reimbursement. If the effect of the time value of money is material, provisions are discounted using a current pre-tax rate that reflects, where appropriate, the risks specific to the liability

Decommissioning provision

Decommissioning provision is recognized when the Company has a present legal or constructive obligation as a result of past events, and it is probable that an outflow of resources will be required to settle the obligation, and a reliable estimate of the amount of obligation can be made. A corresponding amount equivalent to the provision is also recognized as part of the cost of the related property, plant and equipment. The amount recognized is the estimated cost of decommissioning, discounted to its present value using a risk-free rate. Changes in the estimated timing of decommissioning or decommissioning cost estimates are dealt with prospectively by recording an adjustment to the provision, and a corresponding adjustment to property, plant and equipment.

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

Cost
At December 31, 2014	3,800,736
Additions	593,966
Decommissioning provision net additions	15,667
Prepaid capital	6,274
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
Accumulated depletion and depreciation
At December 31, 2014	(903,445)
Depletion and depreciation	(323,139)
At December 31, 2015	(1,226,584)
Depletion and depreciation	(327,080)
At December 31, 2016	(1,553,664)
Carrying amount at December 31, 2015	3,190,059
Carrying amount at December 31, 2016	3,347,859

The Company closed an asset swap arrangement during the year ended December 31, 2016. 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 $12.7 million for the year ended December 31, 2016. The gain is offset by a loss on disposition of assets relating to a disposition of a well and 2016 land expiries. Proceeds received for assets disposed during 2016 were $0.2 million (2015 – $6.1 million). The book value of land was $5.0 million (2015 – $3.5 million), calculating a loss of $4.8 million (2015 – $2.6 million gain).

During, 2016 Peyto capitalized $7.1 million (2015 – $8.0 million) of general and administrative expense directly attributable to exploration and development activities.

At December 31, 2016, the Company assessed whether there were any indications of impairment of assets at the CGU level. The Company determined that there were no indicators that the oil and natural gas properties were impaired at December 31, 2016 and 2015. 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, 2016, future commodity prices and a risk adjusted after tax discount rate of 8%.

The benchmark prices used in the Company’s forecast at December 31, 2016 are outlined as follows:

	2017	2018	2019	2020	2021	2022	2023
AECO natural gas ($/MMBtu)	3.47	3.42	3.59	3.93	4.01	4.17	4.27

Prices and costs subsequent to 2023 have been adjusted for estimated annual inflation of 2%.

4. Long-term debt

	December 31, 2016	December 31, 2015
Bank credit facility	550,000	625,000
Senior unsecured notes	520,000	420,000
Balance, end of the year	1,070,000	1,045,000

The Company has a syndicated $1.0 billion extendible unsecured revolving credit facility with a stated term date of December 4, 2019. An accordion provision has been added that allows for the pre-approved increase of the facility up to $1.3 billion, at the Company’s request, subject to additional commitments by existing facility lenders or by adding new financial institutions to the syndicate. The bank facility is made up of a $30 million working capital sub-tranche and a $970 million production line. The facilities are available on a revolving basis. 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. After the issuance of these notes, the shelf facility is fully drawn at $250 million.

Senior Unsecured Notes	Date Issued	Rate	Maturity Date
$100 million	January 3, 2012	4.39%	January 3, 2019
$50 million	September 6, 2012	4.88%	September 6, 2022
$120 million	December 4, 2013	4.50%	December 4, 2020
$50 million	July 3, 2014	3.79%	July 3, 2022
$100 million	May 1, 2015	4.20%	May 1, 2025
$100 million	October 24, 2016	3.70%	October 24, 2023

Peyto’s total borrowing capacity is $1.52 billion and Peyto’s credit facility is $1.0 billion.

The fair value of all senior notes as at December 31, 2016, is $535.6 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.

Peyto is in compliance with all financial covenants and has no subordinated debt as at December 31, 2016.

Total interest expense for 2016 was $39.3 million (2015 – $35.1 million) and the average borrowing rate for 2016 was 3.7% (2015 – 3.6%).

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, 2014	100,815
New or increased provisions	20,099
Accretion of discount	2,400
Change in discount rate and estimates	(4,432)
Balance, December 31, 2015	118,882
New or increased provisions	16,285
Accretion of discount	2,456
Change in discount rate and estimates	(9,860)
Balance, December 31, 2016	127,763
Current	–
Non-current	127,763

The Company has estimated the net present value of its total decommissioning provision to be $127.8 million as at December 31, 2016 (2015 – $118.9 million) based on a total future undiscounted liability of $258.2 million (2015 – $239.0 million). At December 31, 2016 management estimates that these payments are expected to be made over the next 48 years (2015 – 50 years) with the majority of payments being made in years 2047 to 2065. The Bank of Canada’s long term bond rate of 2.31 per cent (2015 – 2.15 per cent) and an inflation rate of 2.0 per cent (2015 – 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 Common Shares	Amount $
Balance, December 31, 2014	153,690,808	1,292,398
Common shares issued by private placement	230,465	7,732
Equity offering	5,037,000	172,517
Common share issuance costs (net of tax)	–	(5,383)
Balance, December 31, 2015	158,958,273	1,467,264
Common shares issued by private placement	281,270	7,644
Equity offering	5,390,625	172,500
Common share issuance costs (net of tax)	–	(5,426)
Balance, December 31, 2016	164,630,168	1,641,982

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

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

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

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

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.

Shares to be issued

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.

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, 2016 of 162,573,515 (2015 – 157,492,332). There are no dilutive instruments outstanding.

Dividends

During the year ended December 31, 2016, Peyto declared and paid dividends of $1.32 per common share or $0.11 per common share for the months of January to December 2016 totaling $214.9 million (2015 – $1.32 or $ $0.11 per common share for the months of January to December totaling $208.2 million).

On January 13, 2017, Peyto declared dividends of $0.11 per common share that were paid on February 15, 2017. On February 15, 2017, Peyto declared dividends of $0.11 per common share to be paid to shareholders of record on February 28, 2017. These dividends will be paid on March 13, 2017.

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
	2016	2015
Gross field expenses	65,984	69,130
Cost recoveries related to processing and gathering of partner production	(12,753)	(15,009)
Total operating expenses	53,231	54,121

8. Finance costs

	Years ended December 31
	2016	2015
Interest expense	39,380	35,122
Accretion of decommissioning provisions	2,456	2,400
Total finance costs	41,836	37,522

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
	2016	2015
Market based compensation	17,020	12,610
Reserve based compensation	8,750	10,773
Total market and reserves based compensation	25,770	23,383

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

	December 31 2016	December 31 2015
Share price	$22.77	$34.34
Exercise price (net of dividend)	$33.80	$31.29
Expected volatility	0%	0%
Option life	1 – 2 years	1 – 2 years
Forfeiture rate	5%	7%
Risk-free interest rate	0%	0%

The changes in total rights outstanding and related weighted average exercise prices for the years ended December 31, 2016 and 2015 were as follows:

	Rights (number of shares)	Weighted Average Grant Price ($)
Balance, January 1, 2015	3,061,105	$29.40
Granted	3,433,700	$34.35
Cancelled	(257,833)	$31.83
Paid out	(5,232,255)	$31.95
Balance, December 31, 2015	1,004,717	$34.23
Granted	3,798,500	$24.09
Cancelled	(14,000)	$24.67
Paid out	(2,265,551)	$27.78
Balance, December 31, 2016	2,523,666	$24.09

Subsequent to December 31, 2016, 3.8 million rights were granted at a price of $33.80 to be valued at the ten day weighted average market price at December 31, 2016 and vesting 1/3 on each of December 31, 2017, December 31, 2018 and December 31, 2019.

10. Income taxes

		2016	2015
Earnings before income taxes		154,153	223,988
Statutory income tax rate		27.00%	26.00%
Expected income taxes		41,622	58,237
Increase (decrease) in income taxes from:
	True-up tax pools	–	(299)
	Rate change	–	28,158
	Other	183	331
Total income tax expense		41,805	86,427
Deferred income tax expense		41,805	86,427
Current income tax expense		–	–
Total income tax expense		41,805	86,427
Differences between tax base and reported amounts for depreciable assets		(474,918)	(428,439)
Derivative financial instruments		40,701	(16,975)
Share issuance costs		3,545	2,993
Future performance based bonuses		2,728	540
Provision for decommission provision		34,496	32,098
Cumulative eligible capital		5,331	5,733
Charitable donations		62	56
Tax loss carry-forwards recognized		2,043	104
Deferred income taxes		(386,012)	(403,890)

At December 31, 2016 the Company has tax pools of approximately $1,579.9 million (2015 – $1,598.2 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, 2016.

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, 2016 and 2015, 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, 2016:

Natural Gas Period Hedged	Type	Daily Volume	Price (CAD)
April 1, 2015 to March 31, 2017	Fixed Price	50,000 GJ	$2.83/GJ to $3.05/GJ
May 1, 2015 to March 31, 2017	Fixed Price	5,000 GJ	$2.82/GJ
November 1, 2015 to March 31, 2017	Fixed Price	40,000 GJ	$2.84/GJ to $2.975/GJ
December 1, 2015 to March 31, 2017	Fixed Price	5,000 GJ	$2.55/GJ
January 1, 2016 to March 31, 2018	Fixed Price	5,000 GJ	$2.54/GJ
April 1, 2016 to March 31, 2017	Fixed Price	95,000 GJ	$2.58/GJ to $3.01/GJ
April 1, 2016 to March 31, 2018	Fixed Price	60,000 GJ	$2.42/GJ to $2.75/GJ
April 1, 2016 to October 31, 2018	Fixed Price	35,000 GJ	$2.10/GJ to $2.60/GJ
May 1, 2016 to October 31, 2017	Fixed Price	20,000 GJ	$2.11/GJ to $2.305/GJ
May 1, 2016 to October 31, 2018	Fixed Price	20,000 GJ	$2.20/GJ to $2.35/GJ
July 1, 2016 to March 31, 2017	Fixed Price	10,000 GJ	$2.30/GJ
July 1, 2016 to October 31, 2017	Fixed Price	10,000 GJ	$2.375/GJ to $2.3775/GJ
July 1, 2016 to October 31, 2018	Fixed Price	20,000 GJ	$2.28/GJ to $2.45/GJ
August 1, 2016 to October 31, 2017	Fixed Price	20,000 GJ	$2.22/GJ to $2.30/GJ
August 1, 2016 to October 31, 2018	Fixed Price	25,000 GJ	$2.3175/GJ to $2.5525/GJ
November 1, 2016 to March 31, 2017	Fixed Price	175,000 GJ	$2.34/GJ to $3.00/GJ
November 1, 2016 to March 31, 2018	Fixed Price	5,000 GJ	$2.51/GJ
April 1, 2017 to October 31, 2017	Fixed Price	145,000 GJ	$2.23/GJ to $2.86/GJ
April 1, 2017 to March 31, 2018	Fixed Price	110,000 GJ	$2.605/GJ to $3.1075GJ
April 1, 2017 to October 31, 2018	Fixed Price	10,000 GJ	$2.585/GJ to $2.745/GJ
November 1, 2017 to March 31, 2018	Fixed Price	35,000 GJ	$2.91/GJ to $3.27/GJ
November 1, 2017 to October 31, 2018	Fixed Price	5,000 GJ	$2.92/GJ
April 1, 2018 to October 31, 2018	Fixed Price	45,000 GJ	$2.39/GJ to $2.565/GJ
April 1, 2018 to March 31, 2019	Fixed Price	25,000 GJ	$2.555/GJ to $2.6250/GJ
April 1, 2018 to March 31, 2020	Fixed Price	5,000 GJ	$2.50/GJ

As at December 31, 2016, Peyto had committed to the future sale of 254,640,000 gigajoules (GJ) of natural gas at an average price of $2.59 per GJ or $2.96 per mcf. Had these contracts been closed on December 31, 2016, Peyto would have realized a loss in the amount of $150.8 million. If the AECO gas price on December 31, 2016 were to increase by $0.10/GJ, the unrealized loss would decrease by approximately $25.5 million. An opposite change in commodity prices rates would result in an opposite impact on other comprehensive income.

Subsequent to December 31, 2016 Peyto entered into the following contracts:

Natural Gas Period Hedged	Type	Daily Volume	Price (CAD)
November 1, 2017 to March 31, 2018	Fixed Price	35,000 GJ	$2.73GJ – $3.23/GJ
April 1, 2018 to October 31, 2018	Fixed Price	30,000 GJ	$2.37/GJ – $2.54/GJ
April 1, 2018 to March 31, 2019	Fixed Price	5,000 GJ	$2.43/GJ
April 1, 2019 to March 31, 2020	Fixed Price	5,000 GJ	$2.445/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, 2016 would decrease by $6.4 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, 2016, approximately 72% was received from five companies (18%, 17%, 14%, 12% and 11%. (December 31, 2015 – 50% was received from four companies (14%, 13%, 12%, and 11%). Of the Company’s accounts receivable at December 31, 2016, approximately 70% was receivable from five companies (18%, 15%, 14%, 12% and 11%) (December 31, 2015 approximately 74% was receivable from five companies (19%, 16%, 15%, 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, 2016:

	December 31, 2016
Current (less than 30 days)	87,240
31-60 days	3,565
61-90 days	734
Past due (more than 90 days)	3,274
Balance, December 31, 2016	94,813

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, 2016, 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, 2016:

	< 1 Year	1-2 Years	3-5 Years	Thereafter
Accounts payable and accrued liabilities	158,173	–	–	–
Dividends payable	18,109	–	–	–
Provision for future market and reserves based bonus	6,854	–	–	–
Long-term debt(1)	–	–	550,000	–
Unsecured senior notes	–	–	100,000	420,000

(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 2016	December 31 2015
Equity	1,540,934	1,623,557
Long-term debt	1,070,000	1,045,000
Working capital deficit (surplus)	187,186	(3,569)
	2,798,120	2,664,988

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
2016	2015	2016	2015
1,007.0	2,346.3	700.0	911.4

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 $12.4 million in market and reserves based bonus relating to key management personnel for the year 2016 (2015 – $2.0 million in general and administrative and $11.9 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, 2016:

	2017	2018	2019	2020	2021	Thereafter
Interest payments(1)	22,085	22,085	19,890	17,695	12,295	26,645
Transportation commitments	39,415	43,258	35,087	26,872	22,122	80,938
Operating leases	2,444	2,197	2,197	2,197	2,197	10,986
Methanol	818	–	–	–	–	–
Total	64,762	67,540	57,174	46,764	36,614	118,569

(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.

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

Directors
	Don Gray, Chairman
	Stephen Chetner
	Brian Davis
	Michael MacBean, Lead Independent Director
	Darren Gee
	Gregory Fletcher
	Scott Robinson
Auditors
	Deloitte LLP
Solicitors
	Burnet, Duckworth & Palmer LLP
Bankers
	Bank of Montreal
	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
Transfer Agent
	Computershare

Head Office
	300, 600 – 3 Avenue SW
	Calgary, AB
	T2P 0G5
	Phone:	403.261.6081
	Fax:	403.451.4100
	Web:	http://www.peyto.com/
	Stock Listing Symbol:	PEY.TO
		Toronto Stock Exchange

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

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