Peyto Announces Q2 2017 Results, Maintains Industry Leading Cash Costs - Part 1 - Canadian Energy News, Top Headlines, Commentaries, Features & Events

FOR: PEYTO EXPLORATION & DEVELOPMENT CORP.
TSX SYMBOL: PEY

Date issue: August 09, 2017
Time in: 4:30 PM e

Attention:

CALGARY, ALBERTA--(Marketwired - Aug. 9, 2017) - Peyto Exploration & Development Corp. (TSX:PEY) ("Peyto" or the "Company") is pleased to present its operating and financial results for the second quarter of the 2017 fiscal year. A 75% operating margin(1) and a 22% profit margin(2) in the quarter delivered an annualized 10% return on equity (ROE) and 8% return on capital employed (ROCE). Additional highlights included:

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-- Earnings of $0.24/share, dividends of $0.33/share. Earnings of $40

million were generated in the quarter while dividends of $54 million were paid to shareholders. Dividend payments represented a before tax payout ratio of 41% of Funds from Operations ("FFO"), down from 53% in Q2 2016. The Company has never incurred a write down or recorded an impairment and this quarter represents Peyto's 50th consecutive quarter of earnings.

-- Funds from operations of $0.81/share. Generated $133 million in FFO in

Q2 2017 up 31% from $102 million in Q2 2016 (29%/share) as 11% higher production was combined with 15% higher commodity prices. For the first half of 2017, funds from operations were 8% higher than capital expenditures, or $21 million of free cashflow (before dividend payments).

-- Total cash costs of $0.85/Mcfe (or $0.68/Mcfe ($4.11/boe) excluding

royalties). Industry leading total cash costs, including $0.17/Mcfe royalties, $0.24/Mcfe operating costs, $0.18/Mcfe transportation, $0.05/Mcfe G&A and $0.21/Mcfe interest, combined with a realized price of $3.36/Mcfe, resulting in a $2.51/Mcfe ($15.04/boe) cash netback, up 18% from $2.12/Mcfe in Q2 2016.

-- Capital investment of $98 million. A total of 25 gross wells (24 net)

were drilled in the second quarter, 24 gross wells (22 net) were completed, and 29 gross wells (26 net) brought on production. Over the last 12 months new wells brought on production accounted for 34,929 boe/d at the end of the quarter, which, when combined with a trailing twelve month capital investment of $495 million, equates to an annualized capital efficiency of $14,160/boe/d. Peyto had 19 gross wells that were waiting on completion and/or tie in representing an expected 11,500 boe/d of behind pipe production which would have reduced the capital efficiency to the $11,000/boe/d target levels

-- Production per share up 9%. Second quarter 2017 production of 585

MMcfe/d (97,531 boe/d) was up 11% from Q2 2016. The backlog of drilled but uncompleted wells has now been connected with August daily production to date averaging 111,000 boe/d.

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Second Quarter 2017 in Review

The plan to take advantage of reduced industry activity and reduced service costs in the second quarter was partly hampered by heavy rains and wet ground conditions that limited the majority of drilling and completion activity to the month of June. Despite the challenging surface conditions Peyto was still able to drill and complete 25 new wells and bring 29 wells on production. Average drilling costs of $1.8 million/well and completion costs of $0.9 million/well were achieved, consistent with 2016 levels. The liquids pipeline constructed in Q1 2017, connecting four of the nine gas plants, was utilized for the last half of the quarter to reduce liquids trucking in the quarter, increasing the Company's realized liquids prices by approximately $2.50/bbl, and reducing road maintenance and environmental emissions. Operating costs were lower as warmer weather reduced chemical consumption and facility utilizations were optimized. Peyto added 13 sections of new land with pre-identified drilling locations to its inventory of future prospects for an average price of $113/acre. A strict focus on cost control improved operating margins resulting in increased year over year returns on capital employed.

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 quarter 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, particularly if used in isolation as it is based on an energy equivalency conversion method primarily applied at the burner tip and does not represent a value equivalency at the wellhead.

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Three Months Ended June 30 2017 2016 -------------------------------------------------------------- Operations Production Natural gas (mcf/d) 535,274 489,337 Oil & NGLs (bbl/d) 8,319 6,621 Thousand cubic feet equivalent (mcfe/d @ 1:6) 585,187 529,064 Barrels of oil equivalent (boe/d @ 6:1) 97,531 88,177 Production per million common shares (boe/d)(i) 592 545 Product prices Natural gas ($/mcf) 2.92 2.60 Oil & NGLs ($/bbl) 48.33 41.46 Operating expenses ($/mcfe) 0.24 0.26 Transportation ($/mcfe) 0.18 0.17 Field netback ($/mcfe) 2.77 2.39 General & administrative expenses ($/mcfe) 0.05 0.06 Interest expense ($/mcfe) 0.21 0.21 Financial ($000, except per share(i)) Revenue 178,982 140,891 Royalties 9,071 4,874 Funds from operations 133,487 102,178 Funds from operations per share 0.81 0.63 Total dividends 54,408 53,735 Total dividends per share 0.33 0.33 Payout ratio 41 53 Earnings 39,957 9,102 Earnings per diluted share 0.24 0.06 Capital expenditures 97,738 50,634 Weighted average common shares outstanding 164,874,175 161,845,999 As at June 30 End of period shares outstanding (includes shares to be issued Net debt Shareholders' equity Total assets (i)all per share amounts using weighted average common shares outstanding

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%Six Months Ended June 30 % Change 2017 2016 Change --------------------------------------
9% 542,118 528,284 3% 26% 8,949 6,815 31% 11% 595,813 569,171 5% 11% 99,302 94,862 5% 9% 602 591 2%
12% 2.94 2.85 3% 17% 48.23 37.42 29% -8% 0.26 0.25 4% 6% 0.18 0.16 13% 16% 2.78 2.57 8% -17% 0.05 0.04 25% - 0.20 0.19 5%
27% 366,932 320,243 15% 86% 19,707 11,859 66% 31% 272,792 242,085 13% 29% 1.66 1.51 10% 1% 108,796 106,255 2% - 0.66 0.66 - -23% 40 44 -9% 339% 80,211 51,045 57% 300% 0.49 0.32 53% 93% 251,612 226,397 11% 2% 164,837,609 160,494,262 3%
164,874,175 164,630,168 - 1,218,879 1,018,796 20% 1,647,133 1,656,995 -1% 3,604,373 3,389,786 6% (i)all per share amounts using weighted average common shares outstanding

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Three Months Ended Six Months Ended June June 30 30 ($000 except per share) 2017 2016 2017 2016 ---------------------------------------------------------------------------- Cash flows from operating activities 127,980 103,123 249,117 241,241 Change in non-cash working capital 2,191 (9,279) 18,351 (10,391) Change in provision for performance based compensation 3,316 8,334 5,324 11,235 ---------------------------------------------------------------------------- Funds from operations 133,487 102,178 272,792 242,085 ---------------------------------------------------------------------------- Funds from operations per share 0.81 0.63 1.66 1.51 ----------------------------------------------------------------------------

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

Exploration & Development

Second quarter 2017 activity was primarily focused in the Greater Sundance area as wet conditions limited access in Brazeau and other areas during the quarter. Four drilling rigs were active during April and May, while nine rigs were drilling during June. The second quarter drilling activity was entirely focused on the Spirit River group of formations including the Notikewin, Falher and Wilrich. In total, 25 horizontal wells were drilled as shown in the following table:

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Field
Kisku/ Zone Sundance Nosehill Wildhay Ansell Berland Kakwa Brazeau ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Belly River Cardium Notikewin 2 2 1 3 Falher 1 1 1 Wilrich 9 1 3 1 Bluesky ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Total 12 3 5 5 ---------------------------------------------------------------------------- ----------------------------------------------------------------------------
Total Wells Drilled
Zone ---------------------- ---------------------- Belly River Cardium Notikewin 8 Falher 3 Wilrich 14 Bluesky ---------------------- ---------------------- Total 25 ---------------------- ----------------------

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Horizontal well drilling costs in Q2 2017 were in line with Q1 and with 2016 average costs despite the wetter conditions and delays associated with spring breakup. Completion costs (per meter of horizontal lateral) were down from Q1 2017 due to lower service costs and lower completion intensity in the Sundance area versus the Brazeau area. The following table illustrates the progression of cost optimization designed to contribute to lower overall development costs and ultimately greater returns:

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2017 2017 2010 2011 2012 2013 2014 2015 2016 Q1 Q2 ---------------------------------------------------------------------------- Gross Hz Spuds 52 70 86 99 123 140 126 40 25 Measured Depth (m) 3,762 3,903 4,017 4,179 4,251 4,309 4,197 4,313 4,143
Drilling ($MM/well) $2.76 $2.82 $2.79 $2.72 $2.66 $2.16 $1.82 $1.82 $1.89 $ per meter $734 $723 $694 $651 $626 $501 $433 $423 $457
Completion ($MM/well) $1.36 $1.68 $1.67 $1.63 $1.70 $1.21 $0.86 $1.09 $0.96 Hz Length (m) 1,335 1,303 1,358 1,409 1,460 1,531 1,460 1,547 1,498 $ per Hz Length (m) $1,017 $1,286 $1,231 $1,153 $1,166 $792 $587 $705 $641 $ '000 per Stage $231 $246 $257 $188 $168 $115 $79 $83 $76 ----------------------------------------------------------------------------

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Capital Expenditures

During the second quarter of 2017, Peyto spent $48 million on drilling, $21 million on completions, $9 million on wellsite equipment and tie-ins, $17 million on facilities and major pipeline projects, and $2 million on new Crown lands and seismic, for total capital investments of $98 million.

In addition to the 25 gross (24 net) horizontal wells drilled, 24 gross (23 net) wells were completed and 29 gross (26 net) wells were equipped and tied in. Peyto completed construction and commissioned its Greater Sundance liquids pipeline in the second quarter and installed a 6 km, 10" gathering line in West Brazeau, which crosses the Nordegg river and connects several new locations to the Brazeau gathering system.

Peyto also purchased 13 sections of new Crown land at sales in the second quarter, mostly in the Greater Sundance area, for an average purchase price of $113/acre.

Commodity Prices

Average daily AECO natural gas prices were $2.64/GJ in Q2 2017, up slightly from $2.58/GJ the quarter before but up significantly from the $1.33/GJ in Q2 2016. US Henry Hub spot prices increased in a similar fashion. A return to historical norms for natural gas storage helped improve supply demand fundamentals contributing to the increase.