CORPORATE PRESENTATION ANNUAL GENERAL MEETING OF SHAREHOLDERS MAY 24, 2016

Transcription

1 CORPORATE PRESENTATION ANNUAL GENERAL MEETING OF SHAREHOLDERS MAY 24, 216

2 FORWARD-LOOKING STATEMENTS 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 ( 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. May 24, 216 2

3 A MONTNEY FOCUSED BUSINESS MODEL Delphi s Bigstone Montney remains a Top Tier growth asset Maintains favorable economics in the current commodity price environment Free cash generated at payout remains significant Significant drilling inventory on 139 sections of land Ownership of infrastructure provides a cost advantage Expanding throughput capacity as required Driving operating and transportation costs lower Operating costs down 19 percent in Q percent owned water disposal well New fuel gas source with additional compression Condensate trucking cost reduction/optimization Frac innovations and production cost reductions leading to better margins Drilling and completion costs down 33 percent since 214 Delivering top quartile PDP F&D costs and recycle ratios May 24, 216 3

4 A DIRECTIONAL LOOK AT Priorities Through This Structural Reset Maintain financial flexibility Capex in the context of cash flow Reduced debt by 3 percent with Wapiti and Hythe dispositions in 215 Significant hedge position for 216 and 217 volumes 75% of natural gas and 56% of field and plant condensate 95% of revenue stream priced off of US$ Balanced revenue stream (215: 49% Gas, 51% Condensate/NGL s) Manage production growth giving consideration to Hedged volumes and Alliance contracted volumes Replacing PDP reserves with higher netback boes than we are depleting Q1 216 production of 8,395 boe/d up from 8, exit rate One well drilled and waiting on completion Continue to focus on margin growth Higher condensate yields leading to increased revenue per boe Reducing operating costs and condensate transportation costs May 24, 216 4

5 CORPORATE SUMMARY DEEP BASIN NORTHWEST ALBERTA CORPORATE INFO Dawson Creek Trading Symbol TSX:DEE Hythe Grande Prairie Hythe and Wapiti sold in 215 Basic Shares Outstanding Market Capitalization million $179 million Wapiti Bigstone Q1 216 Production 8,395 boe/d Dec. 31, 215 Reserves (P+P) 45.5 mmboe Tower Creek Capital program focused exclusively on the Bigstone Montney liquids-rich resource development Legacy assets: (2,6 boe/d) Wapiti sold July 215 for $5 million Hythe sold November 215 for $12 million Net Debt Mar. 31, 216 Credit Dec 31, 215 $126 million $146.5 million May 24, 216 5

6 BIGSTONE A SINGULAR FOCUS Negus Gas Plant 15 mmcf/d 7-11 Montney Facility 55 mmcf/d K3 Facility Bigstone West Gas Plant 85 mmcf/d W5 Disposal Facility 5-8 Montney Facility 1 mmcf/d 7-11 Tower Creek 25 DEE Producing Montney Horizontals 5-8 Bigstone Montney Acreage May 24, 216 6

7 DOMINANT LAND POSITION Montney land position has grown to 139 gross (117.1 net) sections since 21 Delphi one of the largest Montney landowners on map sheet Delphi continues to be a leader in the technical innovation of the liquids-rich play Exxon Continue to pursue additional Montney acquisition/farm-in opportunities within Greater Bigstone Chevron Development drilling inventory of +1 two mile HZ wells at East Bigstone West Bigstone will require +1 wells to develop Delphi drilling 216 drilling program moving westward Industry offset activity is aiding de-risking area Continue to pursue land consolidation opportunities Exxon ECA West Bigstone ATH DEE East Bigstone Owned and operated infrastructure in place Expanding to match production growth Exxon Fir Resthaven Conoco Exxon South Bigstone May 24, 216 7

8 STRATEGIC INFRASTRUCTURE Delphi owns significant infrastructure at Bigstone 1% owned 55 mmcf/d sour dehy and compression facilities 26% ownership in 85 mmcf/d sweet processing plant Sour processing capacity at SemCAMS K3 Rge25W5 Rge24 Rge23 Rge22 SemCAMS KA Rge19 TCPL Alliance Rge18 Twp 61 Delphi water disposal well operational in Q4 215 Pursuing plans to further optimize netbacks and project economics Delphi 7-11 Twp 6 TCPL Alliance TLM BWGP Future DEE Amine Plant (217?) New 1% DEE Water Disposal Well SemCAMS K3 Alliance TCPL Delphi 5-8 CFGGS Tie-in option to TLM Edson Plant for acid gas Twp 58 Delphi Montney production switched to SemCAMS K3 September/14 Saturn Deep Cut TCPL May 24, 216 8

9 STRATEGIC INFRASTRUCTURE Delphi 1% owned Water Disposal Facility $3 million project Less than 1 year payout Targeted operating costs savings of: $2. to $2.5 million per year or $.7 per Montney boe Targeted completion cost savings of: $3, per well Potential to take third party water Profit center vs cost center Leduc disposal well capable of injection in excess of 4, bbls/d Two truck unloading lanes Simple to increase tank storage as required May 24, 216 9

10 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 ALLIANCE FIRM TRANSPORTATION SERVICE 8. TCPL/Alliance Capacity (mmcf/d) Q1 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 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 May 24, 216 1

11 26 MONTNEY WELLS DRILLED Drilled 3 HZ wells in 212 Conventional gelled oil frac designs Extended reach laterals of 2,2 m to 3, m Drilled 21 HZ wells in ATH 5 wells DEI 3 wells To KA Sour Plant Initial slickwater hybrid frac design Superior production performance Continued innovation of the slickwater frac design NAL 2 wells Delineation of East Bigstone focused on low-risk high productivity infill drilling Drilling 4 to 5 HZ wells in 216 Focused on west side area 3-26 CLT 1 wells Higher condensate yields Increase well density from 4 laterals per section to 5 or 6 Significant drilling inventory for 217 and beyond with ultra-high condensate yields DEE 7-11 Sour Montney Facility Expanded to 55 mmcf/d in Q1 216 XTO 215 Drill DEE 5-8 Sour Montney Facility 1 mmcf/d May 24,

12 CORPORATE AND MONTNEY RESERVES Montney Development (212 to Q1 216) 26 wells drilled life-to-date (LTD) Produced 6.1 million boes in 3.5 years Generated $12 million in field operating income Cumulative capital of $265 million Including $45 million of infrastructure costs 215 PDP FD&A of $1. per boe LTD netback of $19.65/boe with a recycle ratio of 1.4 Montney Proved Producing Reserves (mboe) 19 percent growth in PDP reserves in 215 9,781 11,626 29% PDP 47% PDNP 1% PUD 31% PA 18,625 mboe of dispositions in ,368 31,434 Probable (mboe) 61,662 Proved (mboe) 25,52 Reserves /1, shares 43,63 4,182 19,267 15,18 42,934 36,142 45,463 21,572 4,37 25,74 23,796 23,891 1, May 24,

13 INDIVIDUAL MONTNEY WELL DATA Initial Production (IP) Rate Well Performance (1) Well (2) Conventional Fracs (original completion technique) Number IP3 IP3 IP3 IP9 IP18 IP27 IP365 IP 2yr HZ Length of Fracs Total Sales FCond Rate Total NGL Total Sales Total Sales Total Sales Total Sales Total Sales Yield (metres) (boe/d) (bbls/d) (bbl/mmcf) (boe/d) (boe/d) (boe/d) (boe/d) (boe/d) 16-3 #1 2,76 2 1, #2 3, #3 2, , Slickwater Fracs (new completion technique) 15-1 #4 1, S.BS Expl (3) 1, Type Well 2,4 3, 3-4 1, ,293 1, #5 2,47 3 1, ,667 1,364 1,173 1, #6 2,89 3 1, ,52 1,235 1, #7 2, , ,221 1, #8 3,14 3 2, ,837 1,517 1,324 1, #9 2, , , #1 2, , ,75 1,457 1,268 1, #11 2, #12 2,72 3 1, #13 2, #14 2, , ,217 1, #15 2,61 3 1, #16 2, , , #17 2, , ,296 1, #18 2, , ,337 1, #19 2,82 4 1, #2 2, , , #21 2, , ,47 1, (4) #22 2, , (4) #23 2, , , (4) #24 2, , #25 2,865 waiting on completion Average Wells #5 through #24 1, , (1) Average production calculated on operating days, excludes non-producing days. Includes estimated NGL gas plant recoveries. All production numbers represent sales volumes. (2) Wells numbered chronologically. Slow-back experiment Very strong long term performance (3) Initial exploration w ell on Delphi's South Bigstone lands. Even with payouts stretched to 1.9 years (4) Initial production restricted to tubing flow only. from 1. years previously: boe/d May 24, 216 Significant free cash flow 13

14 INCREASING CONDENSATE YIELDS Geography (East to West) Field condensate yields increase Montney thickens Multiple layers to drill Porosity and Permeability decreases Well spacing decreases Reservoir pressure increases H2S decreases from.8% to sweet Access DEE sweet infrastructure 4 mmcf/d capacity Frac Innovation Larger fracs Higher pump rates Higher sand concentrations Increasing fracture complexity Condensate flow improves DEE Drill IP3 CGR 252 bbl/mmcf ATH 215 Wells IP3 CGR 158 to 242 bbl/mmcf 3-26 XTO 215 Drill CGR 26 bbl/mmcf (based on public data) DEE Type Well IP3 CGR 7 bbl/mmcf DEE Drill IP3 CGR 62 bbl/mmcf May 24,

15 Revenue ($/boe) CONDENSATE YIELDS INCREASING $45. Recent drilling results achieving higher condensate yields $4. $35. $3. $25. $2. $15. $1./boe increase in revenue (before hedges) 15-3 Life-to-Date Type Well Life-to-Date IP IP3 $7.75/boe hedging gain forecast in IP3 Recycle Ratio = Price Forecast AECO Nat Gas: Cdn$1.82/mcf NYMEX Nat Gas: US$2./mmbtu WTI: US$38./bbl Condensate: Cdn$47./bbl NGLs: Cdn$16.5/bbl Increasing the revenue ($/boe) of the new wells more than Delphi's in-the-money hedges New richer wells generate up to a 1.8 PDP recycle ratio on unhedged netbacks PDP F&D of $1./boe Cash costs of 16./boe $ Field Condensate Yield (bbl/mmcf sales) May 24,

16 Revenue ($/boe) YIELD GROWTH REPLACES HEDGING GAINS IN 217 $ $2.1/boe hedging gain forecast in 217 $4. $35. $3. $25. $2. $15. $12./boe increase in revenue (before hedges) 15-3 Life-to-Date Type Well Life-to-Date Recycle Ratio = IP IP IP3 Recycle Ratio = Strip Price AECO Nat Gas: Cdn$2.47/mcf NYMEX Nat Gas: US$2.5/mmbtu WTI: US$45./bbl Condensate: Cdn$54.5/bbl NGLs: Cdn$16.5/bbl 217 drilling program will continue to generate robust new well revenue and netbacks even with less hedging than 216 New richer wells generate up to a 2.3 PDP recycle ratio in 217 on unhedged netbacks PDP F&D of $1./boe Cash costs of 16./boe $ Field Condensate Yield (bbl/mmcf sales) May 24,

17 Boe/d Well Count Gas Rate (mcf/d raw) Field Condensate Rate (bbl/d) MONTNEY ECONOMIC MODEL Bigstone Montney Toe Up Two Section Horizontal Hypothetical Type Well 3 to 4 stage Slickwater Completion Target Capital D,C,E&TI MM$ Initial Sales Production (IP3 - first 3 day average) Gas mmcf/d Total Liquids (C3+) (1,2) Total Liquids (C3+) (1,2) Total IP3 Total Liquids IP3 (C3+) (1,2) Reserves (sales) Gas Liquids (C3+) (1,2) Total bbl/mmcf bbl/d boe/d bbl/d bcf Economics/Metrics - May 11, 216 Strip Pricing (3) mmbbl mmboe $7. Alberta Royalty Framework (4) NRF MRF Payout yrs IRR % 49% 46% NPV 1 MM$ $5.1 $5.3 F&D $/boe $6.13 $ , , 7, 6, 5, 4, 3, 2, 1, 2, 1,5 1, Delphi Energy Bigstone Montney Average All 3+ Stage SW Gas Average Toe Up 3+ Stage SW Gas Type Well Gas Average All 3+ Stage SW FCondy Average Toe Up 3+ Stage SW FCondy Type Well FCondy Flowing Days Delphi Energy Bigstone Montney Average 3+ Stage SW Average Toe Up 3+ Stage SW Type Well Toe Up Well Count Capital Efficiencies IP 9 day = $5,414 boe/d IP 1 year = $8,631 boe/d IP 2 year = $11,966 boe/d (1) Stabilized field condensate beyond month six is 46 bbl/mmcf sales (2) C3: Propane, C4: Butane, C5: Pentane. Gas plant recovered natural gas liquids estimated at 4 bbl/mmcf sales. (3) Strip pricing for 5 years then escalated at 2%/yr thereafter. 216 prices: Henry Hub $2.48/mmbtu US, $3.19/mmbtu CDN; WTI $48.27/bbl USD; C5 $61.79/bbl CDN. 217 Prices: Henry Hub $2.96/mmbtu US, $3.8/mmbtu CDN; WTI $49.82/bbl USD; C5 $62.98/bbl CDN. (4) NRF - New Royalty Framework for wells drilled prior to January 1, 217. MRF - Modernized Royalty Framework for wells drilled after January 1, 217. (5) Type Well reserves and production performance are internal management estimates and may not reflect the actual performance of future wells. Delphi's 17 horizontal toe up M ontney wells at East Bigstone with at least 3 stage fracs were time normalized, averaged and used to determine a proved plus probable reserve estimate. The estimates are used for illustrative purposes and internal corporate planning. 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 Flowing Days May 24,

18 Gas (mcf/d raw) MONTNEY ECONOMIC MODEL Ultra Rich CGR Economic Sensitivities* Initial Sales Production (IP3) & Reserve Assumptions: IP3 Gas Rate 3.6 mmcf/d 1 st Month Field Condensate/Gas Ratio (CGR) 185 bbl/mmcf Gas Reserves 3.9 bcf Alberta Royalty Framework Stabilized CGR after 1 st Month Reserves IRR NRF Payout NPV1 IRR MRF Payout NPV1 (bbl/mmcf sales) (mmboe) (years) (MM$) (years) (MM$) 6, 5, 4, Section W5 Gas Prod vs. Western Bigstone East Type Well for CGR Economic Sensitivities % 1.2 $ % 1.2 $ % 1.4 $9.6 76% 1.4 $ % 1.6 $7.3 57% 1.7 $ % 1.8 $6.4 5% 1.9 $6.9 3, 2, 1, * - Same capital and pricing assumptions as Toe Up Two Section Hypothetical 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/ W5 well which is the western most horizontal montney well brought on production at east Bigstone by Delphi as of December 31, 215 and is constant in the four sensitivities presented above. 12/15-21 has a life to date field condensate to gas ratio (CGR) of 91 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 (March 216) of 82 bbl/mmcf sales. The recent 13/ W5 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. Economics presented here are half cycle, include target capital for well costs to drill, complete, equip and tie-in, and are provided to illustrate sensitivities to field condensate ratios (or yields). No costs for land, central facilities, field gathering infrastructure, corporate costs, etc. are included , 1,2 Flowing Days West Type Well 12/ W5 13/ W5 May 24,

19 PRODUCTION AND OPERATING MARGIN GROWTH 8, 7, 6, 5, 4, 3, 2, 1, Montney Production (boe/d) 1-15% Growth in 216 vs (F) Montney Operating Costs ($/boe) (F) 1,6 1,4 1,2 1, Field Condensate Production (boe/d) Consistent condensate yields over time have supported growth (F) Montney Liquids Yield (bbls/mmcf) Field Condensate Plant Condensate Butane Propane (F) May 24,

20 DELPHI WELL COST IMPROVEMENTS 12, 1, 8, 6, 4, 2, 2, 15, 1, 5, D&C Costs ($ ) IP9 Day Capital Efficiencies ($/boe/d) DEE Well Costs Cost per Frac Stage ($) Avg. Drill Costs Avg. Comp. Costs Avg. Comp. $/Stage Well costs down 36 percent Recent 216 Target 9 Day D&C $ Efficiency ($/boe/d) 9 Day Comp $ Efficiency ($/boe/d) Montney Capital Efficiencies Average drilling and completion costs per well have trended down by 26 percent from $11. million in 212 Latest D&C well costs were $7. million compared to $1.4 in 214 New D&C target set at $6.5 million Further cost savings are being targeted Water disposal Frac design Target IP 9 production data taken from public sources for 212 to 214 May 24, 216 2

21 DRILLING PLANS MOVING WEST Moving West Montney pay thickness increasing 6 laterals per section spacing Two layers to drill 4 Competitor wells drilled and completed Competitor well producing 95 bbl/mmcf condensate Natural gas is sweet DEE sweet infrastructure 4 mmcf/d capacity Condensate and NGL yields: 2 to 4 times greater than East Bigstone type curve Slickwater frac design Delphi 9-4 Well Conventional Gelled Oil Frac in 212 Conoco Completed in 1H 214 DEE activity planned for 2H 216 and well inventory just in this small area ($2 million in capital) Conoco Completed in 215 Conoco Completed in 213 May 24,

22 BIGSTONE CRETACEOUS: OPTIONALITY Bigstone Gething Land W5 Hz Gething Drilled m Hz length 1 stage ball drop, 3T N2 foam frac Concept Well to prove play Area and Play Attributes Delphi operated / high working interest Multiple zones are prospective, with Gething most productive Delphi has over 11 boed production, with 16% liquids TOU s Leland Falher >45 Bcf Cumm Delphi infrastructure in place with low OPEX NGL content : 28 bbl/mmcf Gething Liquids and oil in Cardium, Dunvegan and Second White Specks Falher, Wilrich, Paddy and Cadomin prospective in several areas Bigstone Bluesky to Gething Cross Section LOCATION Untitled Untitled Untitled Tight Sand Exploitation: The Past and The Present Untitled Untitled Untitled Permeability barriers and baffles in the W5 Gething core good well great well the new paradigm Delphi has drilled 25 vertical Gething wells with 98% success since 25 HZ multi-stage fracing technology is the next generation of development high perm interval regional sand May 24,

23 COMMODITY PRICES: MANAGING VOLATILITY CDN/US FX Volatility creates hedging opportunities May 24,

24 CONSISTENT AND PROVEN RISK MANAGEMENT PROGRAM $4 $3 $2 $1 $ -$1 $35 $3 $25 $2 $15 $1 $5 $ -$5 -$1 -$15 Hedging Contribution to Cash Flow ($/boe) Operating cash flow per boe Hedging Gains/Losses ($millions) Natural gas price spike in 28 Hedging gains(losses) per boe Steady decline of natural gas prices from 29 to 213 Collapse of both natural gas and crude oil prices Polar Vortex lifting natural gas prices in 214 Event driven hedging strategy with a long term view of a relatively balanced supply/demand market with events : Mitigates commodity price risk and provides revenue and cash flow certainty Contracts often undertaken around price spike events affecting the futures curve 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 Increased revenues by 8 percent Increased cash flow by 18 percent Added $3.35 per boe to the netback Strategy is proven and repeatable over 2 to 4 year peak to trough event cycles May 24,

25 HEDGES PROTECTING CASH FLOW Natural Gas (Cdn) Apr Dec Volume (mmcf/d) % Hedged (1) 7% 7% Hedge Price (Cdn $/mcf) (2) $3.89 $3.96 Strip Price (Cdn $/mcf) $1.91 $2.71 Natural Gas (US) Apr Dec Volume (mmbtu/d) % Hedged (1) 67% 49% 14% 6% Hedge Price (US $/mmbtu) $3.5 $3.19 $2.79 $2.81 Strip Price (US $/mmbtu) $2.43 $2.97 $2.99 $3. % Hedged in Cdn $ (3) 1% 1% 99% 1% Hedge Price (Cdn $/mmbtu) (4) $4.5 $4.23 $3.7 $4.2 Crude Oil Apr Dec Volume (bbls/d) 8 3 % Hedged (1) 43% 16% Floor Price (WTI Cdn $/bbl) $78.5 $6. Ceiling Price (WTI Cdn $/bbl) (5) $85. $6. Strip Price (WTI Cdn $/bbl) $58.62 $6.95 (1) Percent hedged is based on expected 216 average natural gas production of approximately 35 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 March 31, 216 Mark-to-Market value of approximately $23.1 million May 24,

26 216 GUIDANCE 216 Guidance Average Annual Production (boe/d) 8,3 8,8 Exit Production Rate (boe/d) 8,5 9,5 NYMEX Natural Gas Price (US $ per mmbtu) $2. WTI Oil Price (US $ per bbl) $38. Natural Gas Liquids Price (Cdn $ per bbl) $16.5 Foreign Exchange Rate (US/Cdn) 1.35 Well Count Net Capital Program ($ million) $33. - $38. Funds from Operations ( FFO ) ($ million) $32. - $37. Net Debt at December 31 ($ million) $ $126. Net Debt / Q4 FFO (annualized) May 24,

27 SENSITIVITIES TO 216 FORECAST In the context of 216 forecast pricing: (US$38. WTI and US$2. NYMEX) US$.5/mmbtu change in NYMEX: Cdn$65, cash flow US$5./bbl change in WTI Cdn$2.5 million cash flow CAPEX AND OPEX efficiencies: D&C costs down 35 percent Focused on margin growth 216 CAPEX / CF MATRIX Number of 216 Exit Rate US$ WTI / US$2. NYMEX Gross Wells Production Growth $3. $4. $5. $6. 4 % 122% 16% 96% 87% 5 15% 14% 122% 11% 1% 6 25% 152% 131% 118% 17% Significant hedge position for 216 and 217 Number of 216 DEBT / CASH FLOW MATRIX US$ WTI / US$2. NYMEX Gross Wells $3. $4. $5. $ May 24,

28 217 AND BEYOND Levers Still to be Pulled in an Oil Lower for Much Longer Scenario: Operating efficiency gains lifting unhedged netbacks through 216 and 217 Capital efficiency gains New well innovations are continuing Significant existing infrastructure and processing capacity in place No significant infrastructure capital required in this environment 2 mmcf/d of owned sour Montney capacity available 139 sections to develop 4 mmcf/d of owned sweet processing capacity available OPEX 4 percent lower than sour Montney For sweet Montney as we drill west HZ Gething play being delineating with each Montney well Very low operating costs with existing infrastructure 8 sections to develop May 24,

29 SUMMARY Bigstone Montney is a Top Tier growth asset Large Montney land base of 139 sections Favorable economics and attractive capital efficiencies Remains economic in the trough of the commodity price cycle Continuing to successfully to drive down costs (OPEX, TRANS, G&A and CAPEX) Cash generating capability supported by Montney margin and production growth Montney netbacks top tier with NGL cocktail mix Condensate yields will increase with focused west side drilling activity Stable life-to-date NGL Yields (C3+) of approx. 96 bbls/mmcf Average 69% Condensate Selling approximately 85 percent of our natural gas production into Chicago market Hedges in place through 219 Expecting Bigstone Montney development to increase in 217 May 24,

30 APPENDIX May 24, 216 3

31 EVOLUTION OF THE WORLD-CLASS MONTNEY PLAY Elmworth Large data set 488 Montney wells on production Wapiti Kakwa Delphi Bigstone Source of Data: geoscout May 24,

32 EVOLUTION: PACE OF DRILLING ACCELERATING 2 15 Producing Wells by Rig Release Date Total Wells: 488 Drilling remains active with 16 Montney wells rig released YTD 215 Only 1 wells reporting Montney production as of the date of this analysis 1 5 4, IP18 (mcf/d) by Year 3, Producing Wells by Operator 3, 2,5 2, 1,5 1, This analysis is based upon wells which have Montney production reported and available to the public. Data has been sourced from geoscout. May 24,

33 EVOLUTION: WELL LENGTH INCREASING Number of Wells Average Horizontal Length (m) 3, 2,5 Delphi Ave 2, 1,5 1, 5-1, 1,1-1,5 1,51-2, 2,1-2,5 2,51-3, 3, Horizontal Length (m) 3, 2,5 2, 1,5 1, 5 Average Horizontal Length (m) May 24,

34 EVOLUTION: FRAC STAGES INCREASING Number of Wells Frac Stages per Well Average Number of Frac Stages/Well Delphi Ave Evolution of frac design/recipe has also had a significant positive impact to productivity Average Number of Frac Stages/Well May 24,

35 4,5 4, 3,5 3, 2,5 2, 1,5 1, 5 EVOLUTION: WELL PRODUCTIVITY INCREASING IP9 (mcf/d) 441 wells ,5 4, 3,5 3, 2,5 2, 1,5 1, IP18 (mcf/d) 362 wells , 3,5 3, 2,5 2, 1,5 1, IP365 (mcf/d) 26 wells , 3,5 3, 2,5 2, 1,5 1, 5 IP18 (mcf/d) Delphi Ave IP s based on publicly reported gas rates only May 24,

36 3, 5 4 th Avenue SW Calgary, Alberta T2P 2V6 P (43) F (43) info@delphienergy.ca May 24,