CORPORATE STRATEGY PRESENTATION DECEMBER 216
FORWARD-LOOKING STATEMENTS AND IMPORTANT NOTES The presentation contains forward-looking statements and forward-looking information within the meaning of applicable Canadian securities laws. These statements relate to future events or the Company s future performance and are based upon the Company s internal assumptions and expectations. All statements other than statements of present or historical fact are forward-looking statements. Forward-looking statements are often, but not always, identified by the use of any of the words expect, anticipate, continue, estimate, may, will, should, believe, "intends, forecast, plans, guidance, budget and similar expressions. More particularly and without limitation, this presentation contains forward-looking statements and information relating to petroleum and natural gas production estimates and weighting, projected crude oil and natural gas prices, future exchange rates, expectations as to royalty rates, expectations as to transportation and operating costs, expectations as to general and administrative costs and interest expense, expectations as to capital expenditures and net debt, planned capital spending, future liquidity and Delphi s ability to fund ongoing capital requirements through operating cash flows and its credit facilities, supply and demand fundamentals for oil and gas commodities, timing and success of development and exploitation activities, cash availability for the financing of capital expenditures, access to third-party infrastructure, treatment under governmental regulatory regimes and tax laws and future environmental regulations. Furthermore, statements relating to reserves are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can be profitable in the future. The forward-looking statements and information contained in this presentation are based on certain key expectations and assumptions made by Delphi. The following are certain material assumptions on which the forward-looking statements and information contained in this presentation are based: the stability of the global and national economic environment, the stability of and commercial acceptability of tax, royalty and regulatory regimes applicable to Delphi, exploitation and development activities being consistent with management s expectations, production levels of Delphi being consistent with management s expectations, the absence of significant project delays, the stability of oil and gas prices, the absence of significant fluctuations in foreign exchange rates and interest rates, the stability of costs of oil and gas development and production in Western Canada, including operating costs, the timing and size of development plans and capital expenditures, availability of third party infrastructure for transportation, processing or marketing of oil and natural gas volumes, prices and availability of oilfield services and equipment being consistent with management s expectations, the availability of, and competition for, among other things, pipeline capacity, skilled personnel and drilling and related services and equipment, results of development and exploitation activities that are consistent with management s expectations, weather affecting Delphi s ability to develop and produce as expected, contracted parties providing goods and services on the agreed timeframes, Delphi s ability to manage environmental risks and hazards and the cost of complying with environmental regulations, the accuracy of operating cost estimates, the accurate estimation of oil and gas reserves, future exploitation, development and production results and Delphi s ability to market oil and natural gas successfully to current and new customers. Additionally, estimates as to expected average annual production rates assume that no unexpected outages occur in the infrastructure that the Company relies on to produce its wells, that existing wells continue to meet production expectations and any future wells scheduled to come on in the coming year meet timing and production expectations. Commodity prices used in the determination of forecast revenues are based upon general economic conditions, commodity supply and demand forecasts and publicly available price forecasts. The Company continually monitors its forecast assumptions to ensure the stakeholders are informed of material variances from previously communicated expectations. Financial outlook information contained in this presentation about prospective results of operations, financial position or cash flows is based on assumptions about future events, including economic conditions and proposed courses of action, based on management s assessment of the relevant information currently available. Readers are cautioned that such financial outlook information contained in this presentation should not be used for purposes other than for which it is disclosed. Although the Company believes that the expectations reflected in such forward-looking statements and information are reasonable, it can give no assurance that such expectations will prove to be correct and such forward-looking statements should not be unduly relied upon. Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent known and unknown risks and uncertainties. Delphi s actual results, performance or achievements 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 Delphi will derive therefrom. Should one or more of these risks or uncertainties materialize, or should assumptions underlying forward-looking statements prove incorrect, actual results may vary materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of estimates and projections relating to production rates, costs and expenses, commodity price and exchange rate fluctuations, marketing and transportation, environmental risks, competition from others for scarce resources, the ability to access sufficient capital from internal and external sources, changes in governmental regulation of the oil and gas industry and changes in tax, royalty and environmental legislation. Additional information on these and other factors that could affect the Company s operations or financial results are included in the Company s most recent Annual Information Form and other reports on file with the applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com). Readers are cautioned that the foregoing list of factors is not exhaustive. Furthermore, the forward-looking statements contained in this presentation are made as of the date of this presentation for the purpose of providing the readers with the Company s expectations for the coming year. The forward-looking statements and information may not be appropriate for other purposes. Delphi undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws. The forward-looking statements contained in this presentation are expressly qualified in their entirety by this cautionary statement. The following criteria reflects Montney economic modeling assumptions herein the presentation; 1. Strip pricing for 5 years then escalated at 2% per year thereafter. 217 prices: Henry Hub $3.13/mmbtu US, $4.9/mmbtu CDN; WTI $48.82/bbl USD; C5 $64.2/bbl CDN. 218 Prices: Henry Hub $2.99/mmbtu US, $3.9/mmbtu CDN; WTI $5.93/bbl USD; C5 $66.22/bbl CDN. 2. Type Well stabilized field condensate beyond month six is 46 bbl/mmcf sales; Rich Type Well stabilized field condensate production beyond month one is 116 bbl/mmcf. 3.C3: Propane, C4: Butane, C5: Pentane. Gas plant recovered natural gas liquids estimated at 4 bbl/mmcf sales. 4.Alberta Modernized Royalty Framework for wells drilled after January 1, 217. 5. Type Well reserves and production performance are internal management estimates and were prepared by a qualified reserves evaluator in accordance with the COGE Handbook. Delphi's 18 horizontal toe up Montney wells at East Bigstone with at least 3 stage fracs were time normalized, averaged and used to determine a proved plus probable reserve estimate. 6. Rich Type Well Shale gas reserve assumptions are based on year end 215 GLJ proved plus probable ultimate recoverable assignment of 3.9 bcf for the 12/15-21-6-23W5 well which is the western most horizontal montney well brought on production at east Bigstone by Delphi as of December 31, 215. 12/15-21 has a life to date field condensate to gas ratio (CGR) of 9 bbl/mmcf sales since coming on production in February 214, an initial recoverable proved plus probable reserve CGR assignment of 85 bbl/mmcf sales (total ultimate recoverable P+P reserves of 1.1 mmboe) and a current CGR (July 216) of 82 bbl/mmcf sales. The recent 13/13-21-6-23W5 well was restricted to flow up the tubing only and produced 2.6 mmcf/d sales of natural gas and 662 bbl/d of field condensate over it's first 3 days of production. Reserve estimates include estimated gas plant recovered natural gas liquids of 4 bbl/mmcf sales. 7. Reserve and production estimates are used for illustrative purposes and internal corporate planning and may not reflect the the actual performance of future wells. Economics are half cycle and include target capital to drill, complete, equip and tie-in. No costs for land, central facilities, field gathering infrastructure, corporate costs, etc. are included. December 216 2
CORPORATE SNAPSHOT Ticker Symbol CORPORATE INFORMATION Grande Prairie Bigstone Montney Edmonton TSX:DEE Basic Shares Outstanding (mm) 155.5 Market Capitalization (mm) $175. Bank Debt (1) / Credit Facility (mm) $71.7/ $85. 5 Year Senior Secured Notes (mm) $6. KEY OPERATIONAL FIGURES Q3 216 Production boe/d 8,239 (64% gas) Dec. 31, 215 Reserves (P+P) (mmboe) 45.5 (67% gas) 216 GUIDANCE Average Annual Production (boe/d) 7,7 8, Exit Production Rate (boe/d) (2) Under Review 215 Production Rate Exit 8,3 NYMEX Natural Gas Price (US $ per mmbtu) $2.35 - $2.55 WTI Oil Price (US $ per bbl) $4. - $43. Natural Gas Liquids Price (Cdn $ per bbl) $17. - $19. Foreign Exchange Rate (US/Cdn) 1.3 1.35 Well Count (2) Under Review Net Capital Program ($ million) (2) Under Review Funds from Operations ( FFO ) ($ million) $31. - $34. Calgary (1) Bank debt as of June 216 includes working capital and $6. million of LIC s (2) 216 Guidance under ongoing review due to pending Partner Transaction December 216 3
KEY VALUE HIGHLIGHTS Pure Play Montney E&P Company with WORLD CLASS ASSETS AND A TRACK RECORD OF SUCCESS WORLD CLASS MONTNEY GROWTH ASSET Substantial drilling inventory on 138 sections of land; 8 sections currently fully developed Bigstone Montney economics remain attractive in the current commodity price environment Free cash generated at payout remains significant 1% OPERATIONAL CONTROL MARKET ACCESS & EXCEPTIONAL RISK MANAGEMENT Considerable production growth targets are achievable utilizing existing major infrastructure 1% owned and operated field facilities and pipelines to support profitable growth Operate 1% of Montney development with an average working interest of 84% Drilling and completion costs down 33% and operating costs down 3%, since 214 Added $95 million in cash as a result of an exceptional hedging program Significant hedged position in place through 219 Secured firm service with Alliance to access Chicago gas market for better pricing and fewer curtailments Reduced debt by 3% from the sale of non-core assets now 1% focused at Bigstone RESPONSIBLY MANAGED PROFITABLE GROWTH EXECUTIONAL EXCELLENCE Replacing PDP reserves with higher netback boe s than depleting turning $1 spent into $2 returns Achieving targets within cash flow to accelerate 217 growth with increased liquidity Moderating short-term pace of spend while preserving long-term growth inventory Frac innovations and increased condensate yields leading to better margins Delivering top quartile PDP F&D costs and recycle ratios Top tier well results and capital efficiencies 2 mile extended reach drilling improving overall well results Exceptional management team with a track record of value creation December 216 4
BIGSTONE SOUTHERN END OF PROLIFIC LIQUIDS RICH MONTNEY TREND Elmworth Wapiti Karr 1 8 6 4 Producing Wells by Operator Top 1 in # of Montney Wells Drilled Kakwa 2 Simonette Company Company 1 2 Other Company 3 Company 4 Company 5 Company Company 6 7 Delphi Company 8 2 15 1 Producing* Wells by Rig Release Date Total Wells: 724 Delphi maintains a 1% success rate Bigstone * 473 Wells with IP9 or greater 5, 4, 3, 2, 1, IP18 (mcfd raw) 418 wells Top 3 for 6-Month Production Rates 5 28 29 21 211 212 213 214 215 December 216 5
PARTNER TRANSACTION - LETTER OF INTENT $4 Million Joint Drilling Program Delphi will contribute 15% of the drilling and completion costs ($6 million) while retaining a 65% working interest in the wells; The Partner will carry the remaining 5% of Delphi s share of the drilling and completion costs, to a maximum of $2 million; The program contemplates 5 6 wells drilled before July 15, 217 $3 Million Cash Consideration Delphi will receive $3 million in cash at closing as equalization consideration Deal Status: LOI executed November 4, 216 P&S to be executed by November 3, 216 Planned closing prior to December 22, 216 Delphi will retain operatorship of the Montney capital program, production and facilities. Transaction Assets The Partner will increase working interests, to varying degrees, in partially developed and undeveloped lands, production and infrastructure; 45 barrels of oil equivalent ( boe ) per day (approx. 5% of its productive capability) Total proved reserves of 2.8 million boe (approx.12% of corp.) and associated future development capital of $24.1 million (before escalation) Total proved plus probable reserves of 7.3 million boe (approx.16% of corp.) and associated FDC of $59.3 million (before escalation) The Partner will receive a 35% working interest in Delphi s 1% owned sour processing infrastructure Delphi will assign various working interests in its land base at Bigstone Montney to the Partner; Delphi will hold 65% and the Partner will hold 35% of the combined interests; Delphi s total developed, partially developed and undeveloped land position will change from approx. 117 net sections (138 gross) to 87 net sections (143 gross); Delphi will assign a total of 25.4 net undeveloped sections to the Partner Delphi will receive a total of 2.25 net undeveloped sections from the Partner December 216 6
DOMINANT LAND POSITION IN BIGSTONE MONTNEY Largest Land Position at Bigstone Bigstone Activity by Region East Bigstone manufacturing / development December 216 Current Montney land position grown from 4. to 138 gross (117 net) sections since 21; Significant land position allows for efficient operations, control over infrastructure and scalable development 8 sections currently fully developed with substantial room to grow through drilling Drilling program moving west into ultrarich condensate region West Bigstone industry activity has derisked area South Bigstone exploration opportunity Super-major presence and development activity; Exxon, Chevron, & ConocoPhillips operate in the general area Delphi continues to identify and pursue additional land consolidation opportunities within the Greater Bigstone area WEST BIGSTONE SOUTH BIGSTONE Other EAST BIGSTONE Legend 7
28 BIGSTONE MONTNEY WELLS DRILLED Progressive improvements in Drilling Results Drilled 5 horizontal wells in 212; Average IP3: +1,2 boe/d (19% liquids) 8 Sections Fully Developed 95% of Production Excluded from Equalization Conventional gelled oil frac designs Began extended reach laterals of 2,2 m to 3, m which improved costs Drilled 2 horizontal wells from 213 215; Average IP3: +1,44 boe/d (3% liquids) First mover in slickwater hybrid frac design - improved production performance Continued innovation of the slickwater frac design Delineation of East Bigstone focused on high productivity infill drilling Drilling 4 to 5 horizontal wells in 216; Moving west to target higher condensate yields and increased pay thickness DEE 7-11 Sour Facility Expanded to 55 mmcf/d in Q1 216 Company evaluating increased well density from 4 laterals per section to 5 or 6 Significant drilling inventory on 138 sections for 217 and beyond; Increasing condensate yields Continued cost reduction Legend 212-215 (24 wells) 216 (4 5 wells) Fully Developed Sections DEE 5-8 Sour Facility 1 mmcf/d December 216 8
Operating Costs ($/boe) STRATEGIC INFRASTRUCTURE AT BIGSTONE Significant Infrastructure In Place DEE 11-3 15 mmcf/d Gas Plant DEE 7-11 55 mmcf/d Montney Facility 1% owned 55 mmcf/d sour dehy and compression facilities Legacy sour processing capacity available at SemCAMS K3 and KA TLM BWGP 85 mmcf/d Plant To TCPL Future DEE Amine Plant To SemCAMS Connected to Pembina, TCPL and Alliance Ownership of 4 mmcf/d sweet processing infrastructure 1% owned water disposal well operational in Q4 215 $12. $11. $1. $9. $8. $7. $6. $5. $4. Montney Operating Costs DEE 5-8 1 mmcf/d Montney Facility Operating cost decrease by 3% since 214 to $5.87/boe in Q2/16 212 213 214 215 216E December 216 9
MARKET ACCESS ADVANTAGE Exceptional Gas Marketing Considerable production growth targets are achievable utilizing existing major infrastructure Secured firm service agreement to access larger Chicago gas market for better pricing Pricing has been significantly better than AECO Secured firm service minimizing exposure to curtailments on the TCPL pipeline system Delphi / Alliance Full-path service to Chicago December 216 1
CONSISTENT AND PROVEN RISK MANAGEMENT PROGRAM Consistent Hedge Performance Majority of near term production is hedged Natural Gas Q4/16 Q1/17 Q2 - Q4/17 218 219 % Hedged 75% 65% 59% 3% 21% Hedge Price (Cdn $/mmbtu) $4.54 $4.28 $4.21 $3.77 $3.89 Event driven natural gas hedging strategy with a long term view of a relatively balanced supply & demand; Strategy is proven and repeatable over 2 to 4 year peak to trough event cycles Risk management contracts generally put in place over a 12 to 48 month period Over a 1 year period risk management program has: Realized $95 million in hedging gains Crude Oil Q4/16 Q1/17 Q2 - Q4/17 218 219 % Hedged 49% 73% 49% 16% 16% Floor Price (WTI Cdn $/bbl) $76.44 $66.78 $66.67 $7. $7. Ceiling Price (WTI Cdn $/bbl) $85. $66.78 $66.67 $7. $7. $35 $3 $25 $2 $15 $1 $5 Hedging Gains/Losses ($millions) Natural gas price spike in 28 Steady decline of natural gas prices from 29 to 213 Collapse of natural gas and crude oil prices December 216 Increased revenues by 8% Increased cash flow by 18% $ -$5 -$1 Added $3.35/boe to netback -$15 Polar Vortex lifting natural gas prices in 214 11
MONTNEY GROWTH AT BIGSTONE Bigstone Montney Liquids-Rich Gas Play Southeast corner of Alberta liquids-rich Montney trend, 1 3 bbl/mmcf Condensate & NGL 28 wells drilled life-to-date in the Montney from 212 to Q2 216 138 gross sections of Montney rights (84% average working interest) Thickness of 1m - increasing to the west Better than average rock quality higher Permeability & Porosity, normal to overpressured reservoirs Delphi Montney Wells Drilled 1-14 1, 8, 6, 4, 2, Montney Production (boe/d) Growth is accelerating into 217 212 213 214 215 216 (Exit) Montney Field Condensate Production (boe/d) 2, 1,5 Montney condensate production accelerating with increasing yields 5 6 8 6 4-5 1, 5 December 216 212 213 214 215 216(F) 217 Target 212 213 214 215 216 (Exit) 12
CONSISTENT ECONOMIC RESERVE GROWTH Montney Development (212 to Q3 216) 28 wells drilled life-to-date (LTD) Produced 7.2 million boes in 4.5 years Generated $18 million in operating income Cumulative capital of $325 million; Including $4 million of infrastructure costs Montney Proved Producing Reserves (mboe) Economic Montney reserve growth with 215 PDP FDA of $1.12/boe 1,178 4,37 9,781 11,626 212 213 214 215 Significant Inventory for growth 215 drilling program was focused on infill locations; 19% PDP reserve growth 8 of 138 sections are fully developed Only 3 undeveloped locations in 2P reserves 216 drilling program focused on moving west 16-9 Frac planned for late November Montney 2P Reserves (mboe) 11,6 33,1 5,728 43,434 3 year full-cycle 2P FDA of $1.62/boe LTD netback of $19.65/boe 212 213 214 215 December 216 13
Field Condensate Yield (bbls/mcf) HIGHER CONDENSATE YIELDS BOOSTING ECONOMICS Continuing Frac Innovation Larger fracs Higher pump rates Higher sand concentrations Enhanced fracture complexity Increased condensate yields Successfully re-frac d first well IP3 Montney Field Condensate Yields ATH 215 Wells IP3 CGR 158 to 242 bbl/mmcf DEE 13-21 215 Drill IP3 CGR 252 bbl/mmcf DEE 16-3 Refrac IP3 CGR 11 bbl/mmcf DEE Type Well IP3 CGR 98 bbl/mmcf 3 25 2 15 1 Frac innovation yielding more condensate Netbacks 1.2 to 1.8 times higher 252 XTO 215 Drill CGR 26 bbl/mmcf (based on public data) DEE 12-17 213 Drill IP3 CGR 62 bbl/mmcf 5 8 93 16 132 14 11 - Type Well 15-23 14-11 14-24 14-27 16-3 Refrac Most recent wells 13-21 December 216 14
DELIVERING EXCEPTIONAL MARGIN GROWTH 216 Focus on Margin Growth Paid Off Increased condensate yields and lowered cash costs Q3 216 compared to Q3 215; Condensate production increased 39% Field netbacks (excluding hedging) increased 19% Operating Costs vs. Gas Weight 216/215 Q2 Operating Costs vs. Production Mix Relative Change Source: AltaCorp Capital December 216 15
OUTSTANDING WELL PERFORMANCE At day 158 13-21 gas rate flat at 3mmcf/d Condensate yield at 115 bbl/mmcf sales IP9 (mcf/d) 473 Wells of 724 Wells Drilled 4, 16 48 2 5, 88 33 3 Top Decile for 3-Month Production Rates 57 94 473 3, 2, 1, 59 26 Well Count Gas mmcf/d Sales Production Rate Field Condensate bbl/d Total boe/d Condensate Yield bbl/mmcf IP3 22 4.7 45 1,42 95 IP9 2 4.2 331 1,23 79 IP18 2 3.6 25 988 7 IP27 18 3.2 194 849 61 IP365 15 2.8 166 754 58 December 216 16
Capital Efficiency ($/boe/d) Average Costs ($) DELPHI WELL COST IMPROVEMENTS Montney Capital Efficiencies Delphi Well Costs Drilling & Completions: Average drilling & completion costs per well have trended down by 35%; $11 million in 212 to $7 million in most recent five wells. Record low drilling & completions cost of $6.5 million achieved $12, $1, $8, $6, $4, $2, $ Well costs 35% 212 213 214 215 216 YTD Drilling Costs Completion Costs Avg. Comp. $/Stage $6 $5 $4 $3 $2 $1 $ Average Completion Cost/Stage ($) Additional cost savings are being achieved; IP9 Day Capital Efficiencies 3-4 wells per pad from 2 well pads 15, IP9 Capital Efficiencies: Top decile efficiencies of $6, boe/d. Achieved through cost reductions and robust IP9 rates of 1,2 boe/d. 1, 5, 212 213 214 215 216 YTD 9 Day D&C $ Efficiency ($/boe/d) 9 Day Comp $ Efficiency ($/boe/d) December 216 17
MONTNEY ECONOMIC MODEL Bigstone Montney Toe Up Two Section Horizontal Hypothetical Type Wells 3+ stage Slickwater Completion DEE Type Well Economics/Metrics - August 31, 216 Strip Pricing (1) Type Well Rich Type Well Payout yrs 1.6 1.3 IRR % 56% 81% NPV 1 MM$ $5.6 $1.2 PI 1.8 2.5 F&D $/boe $6.42 $5.51 Target Capital Type Well Rich Type Well D,C,E&TI MM$ $7. $7. Initial Sales Production (IP3 - first 3 day average) Gas mmcf/d 5.1 3.6 Field Condensate (2) bbl/mmcf 98 185 Total Liquids (C3+) (2,3) bbl/mmcf 137 224 Total Liquids (C3+) (2,3) bbl/d 696 84 Total IP3 boe/d 1,542 1,42 IP365 (first 365 day average) Gas mmcf/d 2.9 2.2 Field Condensate (2) bbl/mmcf sales 62 125 Total Liquids (C3+) (2,3) bbl/mmcf sales 11 165 Total Liquids (C3+) (2,3) bbl/d 296 36 Total IP365 boe/d 783 724 Reserves (sales) Gas bcf 4.3 3.9 Liquids (C3+) (2,3) mmbbl.4.6 Total mmboe 1.1 1.3 Rich Type Well 13-21 Yield 2.5x Type Well at 1 bbl/mmcf Note: See Montney Economic Model Assumptions in the Forward Looking Statement and Important Notes December 216 18
PRELIMINARY 217 DRILLING PLANS Accelerating Drilling West Filling infrastructure Montney pay thickness increasing to 15 meters; 6 laterals per section spacing Multi-layer drilling WEST BIGSTONE D3 D2 D1 C EAST BIGSTONE D2 D1 C B1 Up to 8 wells drilled this winter Approx. 5 to 6 wells funded under a joint program Remaining wells will be funded within cash flow Majority expected on production in Q2 / Q3 217 Natural gas is sweet; DEE sweet infrastructure 4 mmcf/d capacity Lower operating costs B1 Condensate and NGL yields; 2x to 4x greater than East Bigstone type curve Slickwater frac design Reservoir pressure increases Significant drilling opportunity over 138 sections Drilled Legend Drilling 217 (Winter) DEE activity planned for 2H 216 and 217 25 3 well inventory just in this small area December 216 19
217 AND BEYOND MAINTAINING KEY VALUES World Class Montney Asset Continued new well innovation; Significant infrastructure and processing capacity in place Letter of Intent in place with an existing industry partner to significantly accelerate development and production growth Market Access Secured firm service with Alliance to access Chicago gas market for stronger pricing Operational Control Considerable production growth targets are achievable utilizing existing major infrastructure No significant infrastructure capital required in this environment, low operational costs Land Inventory 138 sections of Montney opportunity to continue developing Partner to contribute $3 million in cash for working interest equalization Performance Operating efficiency gains lifting unhedged netbacks through 219 217 winter drilling program to double with a second rig $2 million Partner carried cost December 216 NEB, FirstEnergy, EIA, USGS 2
APPENDIX December 216 21
BIGSTONE MONTNEY OVERVIEW Scalable and Repeatable Southeast corner of the unconventional Montney trend Developed with extended reach horizontal wells and slickwater-fracing Material capital cost advantage Continuous hydrocarbon system top to bottom Liquids Rich Nearby deltaic sediment supply Relatively high permeability with a fine sand/silt reservoir Relatively high porosity ranging from 4% to 12% Large Resource in Place Field condensate yields at over 55 bbl/mmcf Recent yields materially higher Significant additional liquids extracted through gas processing Top decile gas rate wells with > 5 mmcf/d IP3 s Porous and Permeable Thickness of 1 metres - increasing to the west Multiple layers to develop December 216 22
Dec-15 Feb-16 Apr-16 Jun-16 Aug-16 Oct-16 Dec-16 Feb-17 Apr-17 Jun-17 Aug-17 Oct-17 Dec-17 Feb-18 Apr-18 Jun-18 Aug-18 Oct-18 Dec-18 Feb-19 Apr-19 Jun-19 Aug-19 Oct-19 Dec-19 Feb-2 Apr-2 Jun-2 Aug-2 Oct-2 DELPHI / ALLIANCE FIRM TRANSPORTATION SERVICE 8. Delphi Transportation Capacity on Alliance / TCPL (mmcf/d) 7. 6. 5. 4. 3. Q3 216 Average Natural Gas Production Staged firm service capacity on Alliance to deliver natural gas to the Chicago gas market with priority interruptible service allocation of an additional 25% capacity. Renewal rights on firm service included in agreement. 2. 1. Incremental firm service on TCPL beginning April 218 as part of TCPL expansion. Renewal rights on firm service included in agreement.. TCPL Firm Alliance Firm December 216 23
CRUDE US$/BBL GAS US$/MMBTU COMMODITY PRICES: MANAGING VOLATILITY NYMEX NatGas vs. Crude Historical Settlement Pricing NYMEX Contract Pricing Volatility creates hedging opportunities CDN/US FX Commodity price volatility creates 2 to 4 year hedging cycles Natural gas prices were historically correlated to Crude prices December 216 24
HEDGES PROTECTING CASH FLOW Natural Gas (Cdn) Jul Dec 216 Jan Mar 217 Apr Dec 217 Volume (mmcf/d) 2.4 2.4 2.4 % Hedged (1) 7% 7% 7% Hedge Price (Cdn $/mcf) (2) $3.89 $3.96 $3.96 Strip Price (Cdn $/mcf) $2.51 $2.52 $2.46 Natural Gas (US) Jul Dec 216 Jan Mar 217 Apr Dec 217 218 219 Volume (mmbtu/d) 22.6 19.1 17. 1. 7. % Hedged (1) 68% 58% 52% 3% 21% Hedge Price (US $/mmbtu) $3.61 $3.24 $3.2 $2.87 $2.92 Strip Price (US $/mmbtu) $2.63 $2.84 $2.92 $2.9 $2.88 % Hedged in Cdn $ (3) 1% 1% 1% 1% 1% Hedge Price (Cdn $/mmbtu) (4) $4.61 $4.31 $4.24 $3.77 $3.89 Crude Oil Jul Dec 216 Jan Mar 217 Apr Dec 217 218 219 Volume (bbls/d) 9 1,35 9 3 3 % Hedged (1) 49% 73% 49% 16% 16% Floor Price (WTI Cdn $/bbl) $76.44 $66.78 $66.67 $7. $7. Ceiling Price (WTI Cdn $/bbl) (5) $85. $66.78 $66.67 $7. $7. Strip Price (WTI Cdn $/bbl) $59.9 $62.77 $65.72 $67.82 $69.23 (1) Percent hedged is based on expected 2H 216 average natural gas production of approximately 33 mmcf/d and 1,85 bbls/d of condensate and C5+ (2) Before deduction of transportation costs to ship production to AECO on the TCPL pipeline (3) Percent of US $ hedge value locked in with Cdn/US FX hedges (4) Before deduction of transportation costs to ship production to Chicago on the Alliance pipeline (5) 4 bbls/d have upside to a ceiling price of $85. per barrel at a deferred cost of $4.2 per barrel (6) Strip pricing as of November 8, 216 December 216 25
INDIVIDUAL MONTNEY WELL DATA Slow-back experiment Very strong long term performance Even with payouts stretched to 1.9 years from 1. years previously: 25-35 boe/d Significant free cash flow December 216 26
LIQUIDS-RICH MONTNEY STUDY ELMWORTH TO BIGSTONE Elmworth Large Data Set 473 Montney wells with IP9 of 724 wells drilled to YE215 Wapiti Company 6 Company 7 Delphi Company 3 Company 4 Company 1 Company 2 Company 8 Company 5 Other Kakwa Delphi Bigstone Source of Data: geoscout December 216 27
LIQUIDS-RICH MONTNEY STUDY ELMWORTH TO BIGSTONE 2 18 16 14 12 1 8 6 4 2 Producing* Wells by Rig Release Date Total Wells (with IP9): 473 28 29 21 211 212 213 214 215 1 Producing Wells by Operator 8 6 4 2 Company 1 Company 2 Other Company 3 Company 4 Company 5 Company 6 Company 7 Delphi Company 8 *Produced for at least 9 days December 216 28
5, 4, 3, 2, 1, LIQUIDS-RICH MONTNEY STUDY PRODUCTION BY OPERATOR (GAS IP S ONLY) IP9 (mcfd raw) 473 wells 16 48 22 88 33 3 57 94 59 26 473 5, 4, 3, 2, 1, IP18 (mcfd raw) 418 wells 15 76 21 41 56 3 31 77 47 24 418 5, 4, 3, 2, 1, IP365 (mcfd raw) 288 wells 15 44 29 5 2 24 26 34 29 17 288 December 216 29
6, 5,5 5, 4,5 4, 3,5 3, 2,5 2, LIQUIDS-RICH MONTNEY STUDY EVOLUTION OF DEPTH & HORIZONTAL LENGTH 2 Average Measured Depth (m) 9 2 42 28 29 21 211 212 213 214 215 61 11 Delphi Avg 177 61 3, 2,5 2, 1,5 1, 5 2 Average Horizontal Length (m) 9 2 42 Delphi Avg 28 29 21 211 212 213 214 215 61 11 177 61 6, 5, 4, 3, 2, Average Measured Depth (m) 3, 2,5 2, 1,5 1, Average Horizontal Length (m) 1, 5 88 22 3 33 48 26 57 59 94 16 473 22 88 57 3 26 48 33 59 94 16 473 December 216 3
3 25 2 15 1 5 35 3 25 2 15 1 5 LIQUIDS-RICH MONTNEY STUDY EVOLUTION OF FRAC DENSITY Average Number of Stages per Well 2 9 19 4 28 29 21 211 212 213 214 215 6 Delphi Avg (29 stages) Average Number of Stages per well 1 176 59 14 12 1 8 6 4 2 2 18 16 14 12 1 8 6 4 2 Average Frac Spacing (m) 6 2 39 16 51 Delphi Avg (97m) 85 166 5 28 29 21 211 212 213 214 215 Average Frac Spacing (m) December 216 31
2 18 16 14 12 1 8 6 4 2 5, LIQUIDS-RICH MONTNEY STUDY EVOLUTION OF FRAC DENSITY Number of Wells - 1 11-15 16-2 21-25 26-3 31-35 36-4 Stages per Well IP18 (mcfd raw) 411 wells 5, 4, 3, 2, 1, 5, 18 8 IP9 (mcfd raw) 465 wells 149 9-1 11-15 16-2 21-25 26-3 31-35 36+ Stages per Well 79 IP365 (mcfd raw) 285 wells 21 28 4, 3, 2, 1, 16 76 133 75 7 2 21 4, 3, 2, 1, 12 66 93 48 47 11 8-1 11-15 16-2 21-25 26-3 31-35 36-4 Stages per Well - 1 11-15 16-2 21-25 26-3 31-35 36-4 Stages per Well December 216 32
LIQUIDS-RICH MONTNEY STUDY EVOLUTION OF PROPPANT PLACED Proppant Placed 1.4 1.2 1..8.6.4.2. Delphi Avg (.76 t/m) 2 8 19 42 61 1 175 59 28 29 21 211 212 213 214 215 6, 5, 4, 3, 2, 1, tonnes t/m IP-9 (mcfd raw) IP-18 (mcfd raw) 5, 5, 4, 3, 43 74 128 77 6 52 4, 3, 7 119 68 51 34 2, 25 2, 38 1, 1, 25. -.25.26 -.5.51 -.75.76-1. 1.1-1.25 1.26-1.5 1.51 + t/m. -.25.26 -.5.51 -.75.76-1. 1.1-1.25 1.26-1.5 1.51 + t/m December 216 33
LIQUIDS-RICH MONTNEY STUDY EVOLUTION OF FLUID PUMPED 5. 4. 3. 2. 1.. Fluid Pumped Delphi Avg (3.65 m 3 /m) 2 8 19 42 61 1 175 59 28 29 21 211 212 213 214 215 2, 18, 16, 14, 12, 1, 8, 6, 4, 2, m3/well m3/m IP-9 (mcfd raw) IP-18 (mcfd raw) 5, 5, 4, 3, 11 193 64 54 45 4, 3, 163 57 49 36 2, 2, 17 1, 1,. - 2. 2.1-4. 4.1-6. 6.1-8. 8.+. - 2. 2.1-4. 4.1-6. 6.1-8. 8.+ m3/m m3/m December 216 34
LIQUIDS-RICH MONTNEY STUDY FRAC TYPES 25 2 15 1 5 228 Frac by Fluid Type 176 17 45 5, 4,5 4, 3,5 3, 2,5 2, 1,5 1, 5 Frac by Fluid Type (mcfd raw) IP-9 IP-18 IP-1YR IP-2YR IP-3YR slickwater water oil surfactant December 216 35
LIQUIDS-RICH MONTNEY STUDY DRILLING EFFICIENCY Over a 6 year period, industry improved overall drilling penetration rates by almost 5%. The faster a well can be drilled, the less it costs. 6 5 4 3 2 1 Average Drilling Days 57 17 31 21 25 94 47 61 19 89 36 497 25 2 15 1 5 Average Penetration Rate (m/d) Only 2 wells in 28 dataset (both with horizontal lateral lengths less than 8m) Delphi Avg 28 29 21 211 212 213 214 215 3, 2,5 2, 1,5 1, 5 Average Horizontal Length (m) December 216 36
3, 5 4 th Avenue SW Calgary, Alberta T2P 2V6 P (43) 265-6171 F (43) 265-627 info@delphienergy.ca www.delphienergy.ca December 216 37