Corporate Presentation August 13, 2015 1 Growing a Premier Natural - PowerPoint PPT Presentation

Corporate Presentation August 13, 2015 1

Growing a Premier Natural Gas Asset Focus on Montney Natural Gas in Northeast British Columbia:  Successfully assembled, explored and de-risked a massive resource play  2.9 Tcfe (488 Mmboe) Proved Plus Probable Reserves (1)  Moving into full development phase supported by PPY – AltaGas Strategic Alliance  Projecting production growth to over 100,000 boe/d in 2019  Fully funded with cash balance, cash flow and syndicated bank credit facilities  5-year plan based entirely on North American sales, with no reliance on LNG  Premium assets in the optimum area  Montney is one of the most economic gas plays in North America  PPY wells have the highest average peak month rate of all Montney operators over the past 3 years  West of BC Royalty Line (larger royalty credit per well)  Current and proposed sales pipelines intersect PPY properties  Ideally suited & situated to be a future west coast LNG supplier (1) See “Disclaimer” section. 2

Corporate Snapshot Financial TSX: PPY PPY is included in the TSX Composite Index 99.8 million Shares Outstanding (1) 107.2 million Fully Diluted Shares Outstanding ($9.24 average strike price) (1) $5.68 - $14.75 52-Week Trading Range $698 million Market Capitalization ($7.00/share) $325 million Syndicated Bank Credit Facilities – Two Year Term ($225 million currently, staged increases to $325 million by Oct. 31, 2016) $104 million 2015 Forecast Capital Expenditures (2) $51 million Net debt (1) (1) As of June 30, 2015. (2) See “Disclaimer” section. 3

Corporate Snapshot Production, Reserves & Net Asset Value 15,931 boe/d H1 2015 Average Production (94% natural gas) 29% increase over H1 2015 Average Production of 12,396 boe/d 2.9 Tcfe Proved + Probable Reserves – Dec. 31, 2014 (1) 68% Increase in 2P Reserves in 2014 30% Increase in 2P Undeveloped Reserves per well in 2014 23% Decrease in 2P FDC per Mcfe in 2014 to $1.13 98 years Proved + Probable Reserve Life Index (2) 25 years Proved Reserve Life Index (2) 5.1 times 2014 Proved + Probable Recycle Ratio (FD&A) 3.1 times 2014 Proved Recycle Ratio (FD&A) 4,215% 2014 Production Replacement (Proved + Probable) $2.6 billion NPV10 Proved + Probable Reserves – Dec. 31, 2014 (1) $2.9 billion Net Asset Value (NAV) (3) $27.50 NAV Per Fully Diluted Share (3) (1) See “Disclaimer” section. (2) Based on fourth quarter 2014 annualized production (3) NAV calculated using the NPV10 of 2P reserves as prepared by GLJ Petroleum Consultants effective December 31, 2014, plus undeveloped land evaluated by Seaton-Jordan & Associates Ltd., plus working capital as of December 31, 2014. NAV Per Share calculated using shares outstanding as of December 31, 2014. 4

Impressive & Consistent Reserves Growth (R) 4.91 500 5 Probable 488 Proved MMboe 2P Reserves Per Share 400 4 Reserves Per Basic Share (boe/share) • 164% compound annual growth in 3.28 reserves from 2007 to 2013 Reserves (MMboe) 300 3 • 88% compound annual growth in 290 reserves per share 2.17 MMboe 1.96 200 2 100 123 1 0.70 MMboe 0.19 60 0.13 0.06 MMboe 0 0 2007 2008 2009 2010 2011 2012 2013 2014 5

Dec. 31, 2014 Canadian Natural Gas Reserves Cost of Supply 8,000 30% Increase in 2P Undeveloped 7,000 Reserves per well in 2014 Canadian Natural Gas 2P Resrves (Bcf) 6,000 5.1 times 2014 Proved + Probable Recycle Ratio (FD&A) 5,000 $1.48 $FDC/mcfe in 2013 4,000 to $1.13 $FDC/mcfe in 2014 3,000 2.6 Tcf 2,000 1,000 0 Source: Company press releases and Annual Information Forms. * KEL + RTK 6

Impressive & Consistent Production Growth (P) ~40,000 boe/d Exit (5-Year 25,000 250 Gas Model) Oil & NGL Production per Million Shares 23,000 boe/d 20,000 200 (5-Year • 145% compound annual growth in Model) production from 2007 to 2014 boe/d per Million Shares Production (boe/d) • 76% compound annual growth in 16,000 15,000 150 boe/d (Guidance) production per share from 2007 to 2014 13,192 boe/d (Actual) 10,000 100 5,000 50 0 0 2008 2009 2010 2011 2012 2013 2014 2015E 2016E 7

Top Wells Among All Montney Operators 7 276 140 Painted Pony (6.2 MMcf/d) 6 120 2013-2014 Average Peak Month Rate (MMcf/d) Painted Pony Average Peak Month Rate 2 Times Average 5 100 4 80 Well Count Average 3.1 MMcf/d 3 60 2 40 1 20 0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 Operator Rank Source: geoSCOUT 8

The Montney Trend in Western Canada A Leading North American Gas Play Key Attributes  Tight dolomitic siltstone reservoir Better reservoir than a shale  300 meters (1,000 ft.) thick 4x Thicker than the Marcellus  Continuous gas-saturated zone No associated or underlying water  Sweet gas No acid or sour gas residue  High heat content gas Associated gas liquids enhance gas value  3 distinct layers proven commercial to date 4 - 6 Layer potential under full exploitation Map area  Excellent pipeline egress to N. American markets With existing spare capacity 9

Painted Pony’s Montney Position Premium Assets Located in the Optimum Area Key Attributes  Large contiguous land base with year-round access 217 Net sections (139,049 net acres) 2nd Largest position in northern Montney west of royalty line  High working interest Average 75%, with operatorship on all key properties  Significantly over-pressured reservoir (sweet spot) Northern Montney Development Area  Attractive B.C. provincial royalty structure $2.2 million average royalty credit per well  Highest avg. peak rate among Montney operators 77 wells drilled to date (59 operated by PPY) ~249 locations in 5-year plan PPY Lands  High gas liquids (C3+) content Petronas Lands Shell Canada Lands Up to 60 bbls/MMcf forecast yield at Townsend Royalty Line 1,080 Btu/scf residual heat content Major Gas Pipelines  Proven low cost operator as well costs continue to Montney Wells Southern Montney Development Area Alaska Highway decrease 10

Budget & Risk Management Well hedged into 2016-2017 2015 Budget Alaska Highway $104 Estimated expenditures (millions) Blair 8.0 Gross and net wells - pre drills for Townsend Plant in 2016 West Alliance Pipeline Blair 14.0 Total gross and net planned drills 5 miles>> 10.0 Gross and net planned completions Cypress Daiber AECO Hedges (CDN$)* 2015 Q2-Q4 34.2 MMcf/d at $3.49/Mcf 2016 Q1 59.8 MMcf/d at $3.35/Mcf 2016 Q2-Q4 59.8 MMcf/d at $3.36/Mcf Map Spectra Pipeline Area 2017 Q1 59.8 MMcf/d at $3.36/Mcf Tow nsend 2017 Q2 38.5 MMcf/d at $3.39/Mcf Nov. 5 2014 2017 Q3-Q4 31.6 MMcf/d at $3.49/Mcf Purchase 2018 Q1-Q2 10.3 MMcf/d at $3.57/Mcf 2018 Q3 5.1 MMcf/d at $3.59/Mcf Partner Operated Pads * Assuming an average heating value of 1.17 GJ/Mcf PPY Operated Pads 2015 Active Pads 11

Improved Performance Through Technology Open-Hole Ball-Drop Completions PPY-operated Ball-Drop Completions Ball-Drop vs. Perf. & Plug Completions a-A091-F (Ball-Drop) 7 100% a- 091-F (Perf. & Plug) 90% 6 % Improvement 80% 5 26-L (3) 70% Mcf/d) 5-K (2) West 60% Producing Rate (M 4 Blair 91-F (3) 50% Blair 3 79-E (2) 40% 41-F (2) 30% 11-F (2) 2 6-F (3) 20% 14-F (3) 1 Average cost savings per well of $750,000 10% 44-C (5) 0 0% 1 2 3 4 5 6 7 8 9 10 11 12 13 Daiber Production Month a-A91-F/94-B-16 Ball-Drop Completion  Peak test rate: 8.7 MMcf/d (1,870 boe/d) 11-J (6)  Cumulative production: 1.8 Bcf over 13 months 2-J (2) 56-H (2) a-91-F/94-B-16 Perf-and-Plug Completion Tow nsend  Peak test rate: 6.7 MMcf/d (1,450 boe/d)  Cumulative production: 1.4 Bcf over 13 months 12

Improved Performance Through Technology Parallel-Pair Completion 26-L (1) Region of Completion 5-K (1) West Enhancement Blair Blair 300-350 m 41-F (1) ~ 90-100 m Average Inter-well Spacing Fracture Stage Spacing 11-F (1) 6-F (Triple) 14-F (1) 44-C (1) Ball-Drop Packer Daiber 2015 Drilling Activity are all Parallel-Pairs 11-J (1) 2-J (1) Individual Stage Stimulation Tow nsend Envelop Surface Pad 13

PPY Average Montney Well Production - Blair-Daiber Technology Drives Step-Change Improving Capital Efficiencies 14

PPY Average Montney Well Production - Townsend Technology Drives Step-Change Improving Capital Efficiencies 15

Townsend Development Plan Economics & 2015 Program Development Program Economics  $6.7 million (CDN$) Drill, complete, and equip (2015 ↓10%)  7.4 MMcfe/d I.P. 30 production rate  9.5 Bcfe P+P reserves per well (includes 420 Mbbl of liquids)  60 bbls/MMcf Liquids recovery (C3+)  $8.9 million (CDN$) NPV 10% per well  59% Internal rate of return (IRR)  1.7 years Payout period (from spud) Activity Highlights  Expect to drill 10.0 net wells in 2015 including 8.0 net pre-drills for the Townsend Plant Alaska Highway  AltaGas has commenced refrigeration plant construction Blair West Alliance Pipeline Blair 5 miles>> Cypress Daiber GLJ Price Deck (July 1, 2015) 2015 2016 2017 2018 NYMEX (US$/MMBtu) $2.95 $3.30 $3.50 $3.70 Spectra Pipeline Enlarged Tow nsend Map Area WTI (US$/bbl) $57.26 $67.50 $70.00 $75.00 Nov. 5 2014 Purchase 16