A Growth-Oriented Oil and Gas Company in the Alberta and BC Foothills

Transcription

1 A Growth-Oriented Oil and Gas Company in the Alberta and BC Foothills

2 Certain information with respect to Ikkuma Resources ( Ikkuma or the Corporation ) included in this presentation constitutes forward-looking information under applicable securities legislation. Forward-looking information typically contains statements with words such as anticipate, believe, expect, plan, intend, estimate, propose, project or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information in this presentation may include, but is not limited to, potential flow rates from recently completed wells, the number of derisked, low risk drilling locations, the number of offset locations, the timing of future drilling operations, the potential future OPEX in the $ $4.50 range, expected future well flow rates, the type and timing of capital expenditures, the estimated economic outcome of new gas and oil wells and recompletions, Ikkuma s commitment to spend within cash flow and Ikkuma s future growth resulting from its emerging light oil play. Forward-looking information is based on a number of factors and assumptions which have been used to develop such information but which may prove to be incorrect. Although management believes that the expectations reflected in its forward-looking information are reasonable, undue reliance should not be placed on forward-looking information because there can be no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this presentation, assumptions have been made regarding and are implicit in, among other things, expectations and assumptions concerning the performance of existing wells and success obtained in drilling new wells, anticipated expenses, cash flow and capital expenditures and the application of regulatory and royalty regimes. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., 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 reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), commodity price and exchange rate fluctuations and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. Forward-looking information is based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by the proposed management and described in the forward-looking information. The forward-looking information contained in this presentation is made as of the date hereof and management undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws. The forward-looking information contained in this presentation is expressly qualified by this cautionary statement. This presentation contains the term netbacks which is not a term recognized under IFRS. This measure is used by management to help evaluate corporate performance as well as to evaluate acquisitions. Management considers netbacks as a key measure as it demonstrates its profitability relative to current commodity prices. Operating net backs are calculated by taking total revenues (net of realized hedging gains or losses) and subtracting royalties, operating expenses and transportations costs on a per BOE basis. BOE Disclosure The term barrels of oil equivalent ( BOE ) may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet per barrel (6Mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All BOE conversions in the report are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil, which may be misleading as an indicator of value given that the values are based on the current price of crude oil and natural gas is significantly different from the energy equivalency of 6:1. In this presentation: (i) mcf means thousand cubic feet; (ii) mcf/d means thousand cubic feet per day (iii) mmcf means million cubic feet; (iv) mmcf/d means million cubic feet per day; (v) bbls means barrels; (vi) mbbls means thousand barrels; (vii) mmbbls means million barrels; (viii) bbls/d means barrels per day; (ix) bcf means billion cubic feet; (x) mboe means thousand barrels of oil equivalent; (xi) mmboe means million barrels of oil equivalent and (xii) boe/d means barrels of oil equivalent per day. 2

3 Future Drilling Locations Unless otherwise specified, the information in this Corporate Presentation pertaining to future drilling locations or drilling inventories is based solely on internal estimates made by management and such locations have not been reflected in any independent reserve or resource evaluations prepared pursuant to NI Similarly, unless otherwise specified, the information in this Corporation Presentation pertaining to targeted reserve volumes from future drilling is intended to indicate that in making its internal drilling decisions, the Corporation seeks to target drilling locations that, based on previous drilling results and its own internal assessments, it believes will on average ultimately generate the indicated volumes. This Corporate Presentation discloses drilling locations which are unbooked locations and are internal estimates based on the Corporation s prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources and have been identified by management as an estimation of multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that Ikkuma will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which the Corporation actually drills wells will ultimately depend upon the availability of capital, regulatory approvals, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where management has less information about thecharacteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production. Of the 52 development locations shown on p.18, six are proved plus probable locations identified in the 2016YE Sproule Report. Well Test Results Certain well test results disclosed in this Corporate Presentation represent short-term results, which may not necessarily be indicative of long-term well performance or ultimate hydrocarbon recovery therefrom. Full pressure transient and well test interpretation analyses have not been completed and as such the flow test results contained in this Corporate Presentation should be considered preliminary until such analyses have been completed. 3

4 Strategy Focus Symbol Shares Outstanding: Basic / Diluted Market Capitalization: Basic / Diluted (1) High growth, low decline, gas-weighted, oil upside, in conventional bypassed reservoirs Alberta & BC Foothills TSX-V: IKM 94.2 MM / 98.4 MM $66 MM / $69 MM 2016 Exit Net Debt $32.5 MM Current Production (2) Reserves (1P/ 2P) (3) Infrastructure Current Net Undeveloped / Net Developed Land Tax Pools 6,500-7,000 boe/d (98% gas-weighted) 19.9 MMboe / 27.5 MMboe 560 km pipelines; 9 processing facilities; and ownership in 3 gas plants 159,917 / 63,947 acres $207 MM Insider Ownership: Basic / Diluted (4) 16% / 20% (1) Based on $0.70/share. (2) Present variance is due to curtailments, shut-in production (in some cases for economic reasons). Approximately 500 boe/d, sour gas, remains shut in for economic reasons. (3) Reserves evaluation from the 2016YE Sproule Report. (4) Includes Royal Capital Management Corp. 4

5 Proven Team Technical team with 150+ years of combined foothills operational experience. Successfully mitigated low commodity prices in 2016 with hedging; 4,265 boe/d of 2017 gas production is hedged at $2.86/Mcf (AECO). Top quartile cost efficiencies amongst a select list of Canadian producers. Low Decline Core Asset 10-15% annual decline. Core asset OPEX is approximately $8/boe and future reductions are anticipated. Sweet gas redirect potential within existing infrastructure will further decrease OPEX. Growth Potential 89% WI in an emerging foothills Cardium light oil play with a potential drilling inventory of 150+ locations. Over 50 gas drilling locations planned when gas prices support drilling. Underutilized extensive midstream assets poised for future growth. 5

6 Low decline, stacked reservoirs (Wilrich, Falher, Cadomin, Cadotte, Dunvegan, Cardium), containing oil and gas. Identified multiyear drilling inventory for gas and potentially large (bypassed) oil pools. Team was involved previously in building the asset; 9 facilities, including 3 gas plants, ~560 km pipelines. (2) Highly focused with numerous undeveloped stacked conventional structured reservoirs. 32% 12% N.E. limit of Foothills Play 7% 11% 2% Area production, as a percent of total (1) 20% IKM Trunk Pipeline (1) Approximately 16% of total production is in southern Alberta Foothills. (2) Estimated replacement value of $ MM. 6

7 Cardium Oil and Gas Pools > 4,500 producing Cardium HZ wells in western Canada. Narraway Many junior s exploiting Cardium pools in the deep basin, including: Torc (Kaybob, Rosevear, Carrot); Vermillion, Bellatrix, Bonterra, Arc in Pembina; Bonavista, Yangarra, Taqa (Williston Green); Petrus, Bellatrix, Bonavista (Ferrier); Pengrowth, Whitecap, Exxon (Harme); Orlen (Lochend). Cardium is the largest conventional onshore oil pool in western Canada. 7

8 Approximate Oil Pool Outline Discovery Well #1, 1999 (vertical well), IP 220 bbl/d, 31Mbbl Average 88% WI in 40 sections of land. Regional hydrocarbon charge and extensive, well developed fracture network in a conventional reservoir with porosities up to 12%. Q1, Q2 Drilling Operations Two New Oil Pool Discoveries: W6 and W locations have been identified so far. Based on regional analysis and other Cardium foothills analogues, initial rates could be as high as 200 1,300 boe/d. Reservoir quality and occurrence of condensate appears comparable to other foothills oil reservoirs. Condensate can trade at a $3- $10/Bbl premium to Edmonton Light. 8

9 Large pool with two play types: deep basin resource play and foothills fractured conventional play. Reservoir quality as good, or better than, many deep basin Cardium plays. Cardium is characterized by 15-18m of clean sandstone with porosities up to 12%. Reservoir is above bubble point. Deep Basin Resource Play Scalable, repeatable oil program with focus on D&C optimization for improving economics. Apply deep-basin operator learnings to optimize stimulation and lateral lengths to maximize IP30. Deep basin locations characterized by longer laterals and multi-stage fracture stimulations. Natural fractures are anticipated in deep basin areas, but less common than in faulted areas. Foothills Fractured Conventional Play High permeability sweet spots anticipated in many of the 150+ locations identified to date. Geosteering to remain in porous, fractured intervals is fundamental for increased production. Highly fractured foothills locations may or may not require fracture stimulations. Economics anticipated to be better in fractured fairways. 9

10 Operations to Date Recompleted bypass Cardium and free flowed 75 bbls/d 50 API oil unstimulated (confirmed fracture network, expanded oil fairway). Drilled and fracked horizontal footwall Cardium well with 670m lateral. Currently pumping back frack water, light oil, and sweet gas. After 3.5 months, currently producing about bbl/d fluid (10-30% water), with boe/d gas. Drilled offset hanging-wall exploration well that confirmed new pool and oil charge over multiple thrust sheets. Well is currently pumping between 150 and 350 bbl/d fluid (5-30% water), with boe/d of associated gas. IKM Cardium horizontals in the percentile in the basin, despite being the initial 2 wells in the program. Approximate Initial Production Rates of Wells #1 and #2 Future Operations Q Drill 2 HZ well locations offsetting discovery vertical well that produced over 200 bbl/d, IP30, light oil. 1 development well and 1 exploratory well. Q2-Q Complete and bring wells on production, install facilities. 2-3 gas recompletions. 1 0

11 EUR (BBL) 300, , , , ,000 50,000 - Deep Basin Oil Pools Foothills Oil Pools EUR vs PhiH Cordel Stolberg Lochend NW Pembina E Pembina N Pembina Rosevear Ferrier Kaybob Wapiti Wilson Ck Med River Berland Pine Creek Fir Harme Notin-Carrot Will Grn Kakwa Edson Narraway PhiH Deep basin pools consistently display lesser reservoir PhiH. Foothills Pools (Cordel and Stolberg) have the added benefit of natural fractures, resulting in increased reservoir capability. Narraway (PhiH) reservoir quality is excellent compared to most producing fields. PhiH (1) Pools are heterogeneous. Representative logs were selected in order to determine porosity and reservoir thickness. Cardium reservoir variability is assumed ubiquitous. (2) Cardium gas wells are excluded from the analysis. 11

12 More than 3,500 HZ wells have tested various Cardium deep basin oil pools (see appendix). Only two large foothills Cardium oil pools produced to date in the WCSB (Cordel and Stolberg). (2) Prod. Rate (bbl/d) OIL PD RATE (ALL CARDIUM DEEP BASIN HZ WELLS, IP30) Oil CD Rate GOR Well Count =3, GOR (scf/bbl) Foothills oil pools yield the highest returns due to enhanced permeability Months Expected oil recovery typically much higher in fractured foothills reservoirs, as indicated in graph to right. Based on regional analysis, oil recovery for the foothills Cardium at Narraway is expected to be higher than the deep basin reservoirs with comparable porosities. (1) EUR for new wells cannot be estimated at present. (2) WCSB Western Canada Sedimentary Basin; also see Appendix. 12

13 150+ locations. (1) Estimated 30 well, 3 year program with a projected $127 MM CAPEX requirement. Generates peak annualized cash flow of $82MM/yr (Feb 2017 Strip pricing). Peak production 6,508 boe/d, with less than of 25% locations drilled. Risked IRR 85%, on strip pricing. (2) Feb 2017 (Strip) C$/bbl $/mcf Jan-17 $ $ 2.80 Jan-18 $ $ 2.70 Jan-19 $ $ 2.50 Jan-20 $ $ 2.50 Jan-21 $ $ 2.50 Jan-22 $ $ 2.70 Jan-23 $ $ 2.78 Jan-24 $ $ 2.86 Jan-25 $ $ 2.94 Jan-26 $ $ 3.02 Jan-27 $ $ 3.10 Jan-28 $ $ 3.18 IP BBL/d IRR vs IP (MRF) Strip Pricing 0 0% 100% 200% 300% 400% 500% IRR (%) IP (bbl/d) NOI ($/mo); BOE/d FORWARD MODEL (1) 8,000 $ ,000 $ ,000 5,000 $ ,000 $ ,000 2,000 $- 1,000 - $(50.00) Aug-16 Mar-17 Sep-17 Apr-18 Oct-18 May-19 Dec-19 Jun-20 Jan-21 Jul-21 CAPEX ($MM/mo) BOE/d NOI ($M/mo) Cummulative CAPEX ($MM) NOI Minus CAPEX (cummulative $MM) (1) Based on Management estimates. (2) IP 300 boe/d, $ MM/well, 60% initial decline rates. Model contains 30 wells. 13

14 In the southern part of IKM s asset base, there is at least 120 MMcf/d gas processing and transporting capability that could bring OPEX to $4.25-$4.50/boe, thus becoming one of the lowest cost producers in the basin. Potentially lower OPEX and low decline conventional reservoirs provides long term value in a volatile commodity environment. 560 km of operated pipelines gives Ikkuma several options to deliver gas to multiple processing points. Ownership in 3 gas plants and optionality in at least 3 additional, underutilized gas processing facilities. With increasing production, trunk line volumes may be managed more effectively. Elmworth Narraway (7% WI) Unused capacity ~100 MMcf/d Edson Horse Copton (70% WI) Leland (39% WI) Unused capacity ~120 MMcf/d IKM Pipeline 14

15 Exceptionally low corporate decline drives best-in-class growth capital efficiencies. Late-life production and strong conventional reserve bookings. New wells add to strong PDP bookings. 45 CORPORATE PRODUCTION BASE DECLINE % Base Decline IKM CVE CJ PNE EGL IKM ZAR NBZ SGL PGF PSK GXO CNQ SGY FRU HSE JOY AET OIL TOG ERF ARX ATH MPG MQL PWT PXX SPE WCP RE CKE BNE BNP YO LTS MEI VET LRE TBE BXO CPG PMT SKX TVL LXE BIR GXE TVE AAV DEE ECA TET KEL KCK NVA BTE YGR LEG RMP PEY PPY POU VII CR RRX TOU BXE CQE Source: Averaged interpreted base declines of First Energy (July 2015), TD (Aug 2015), and Scotia (May 2015) 15

16 IKM $/boe Source: Beacon Securities, September,

17 IKM More Conservative Less Conservative IKM Source: TD, April,

18 Opportunities Identified to Date 52 gas development locations (>45 Mboe/d net potential). (1) recompletions (>5 Mboe/d net potential). (1) 29 Locations : North (5 Dunvegan, 2 Cadotte, 14 Falher, 8 Nik) 13 Locations : Central (4 Dunvegan, 1 Cadotte, 6 Falher, 2 Nik) Recompletions within Core Asset Base (incl. Cardium, Dunvegan, Cadotte, Falher, Gething, Nik) 10 Locations : South (5 Dunvegan, 3 Falher, 2 Nik) (1) Of the 52 gas locations identified, 6 locations are booked as proven + probable. 18

19 IKM W6 Current Rate (boe/d) , , , , , , ,000 Cumulative BOE to date Best-in-class recompletion results as compared to NBF top wells for January Proven offsets to drill. About 6 offsetting locations that are 100% owned by IKM. Excellent returns, even at low commodity prices. Source: National Bank Financial March 9, 2016 Industry Comment. Public (GeoScout) data added for W6. Operator Well Date Boe Boed/d Crescent Point W3/ , Crescent Point W2/ , Crescent Point W3/ , Tourmaline W5/ , Shell W5/ , ConocoPhillips W5/ , Cdn Nat W6/ , Shell W5/ , Encana W5/ , Seven Generations W6/ , Encana W5/ , Seven Generations W6/ , IKM W , Peyto W5/ , Westbrick W5/ , Cdn Nat W5/ ,726 1,058 19

20 In Q1 2015, completed one of the most prolific unstimulated wells in western Canada in recent years. Recompletion and tie in capital of $1,200 k. Tested at 20 MMcf/d (3,435 boed/d) and potential to flow at more than 30 MMcf/d (5,167 boe/d) at pipeline pressure (gross, 50% net APO). Flow rates during test were constrained by surface equipment. Details of the flow test were disclosed separately by the Corporation on April 6, Each recompletion identified/de-risked ~6 additional drilling locations (12 wells de-risked total). Presently flowing inline at approximately 4-6 MMcf/d. $14,000 $12,000 $10,000 $8,000 $6,000 $4,000 BREAKEVEN ANALYSIS P70 P90 Feb 2017 (Strip) C$/bbl RECOMPLETION INPUTS P70 $/mcf Jan-17 $ $ 2.80 Jan-18 $ $ 2.70 Jan-19 $ $ 2.50 Jan-20 $ $ 2.50 Jan-21 $ $ 2.50 Jan-22 $ $ 2.70 Jan-23 $ $ 2.78 Jan-24 $ $ 2.86 Jan-25 $ $ 2.94 Jan-26 $ $ 3.02 Jan-27 $ $ 3.10 Jan-28 $ $ 3.18 P90 $2,000 $- -$2,000 -$4,000 $- $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 IP (MMcf/d) 12 6 Production (Bcf) 11 8 Recomplete/equip CAPEX ($MM)* $1.20 $1.20 Payout (years) NPV10% ($M) at $3.00 flat price $12,067 $7, *2014 CAPEX estimate (costs could be 30% less than listed based on present industry discounts). 20

21 Why own IKM stock? 1. Unique business model matched with the right team Experienced technical team with highly specialized engineering and geoscience skills. Underexploited part of the basin: prolific conventional reservoirs proven to exist in bypass zones, based on Ikkuma s recompletion results to date. Significant undeveloped land position with few barriers for acquiring new land; since 2014, IKM has grown its undeveloped land base by 157% to 167,000 net undeveloped acres. 2. Solid base production Low cost producer. Low corporate decline, generates exceptional production growth capital efficiency. Natural gas production well hedged through Leading G&A efficiencies. 3. Clear path to growth Exceptional results to date: some of the best gas wells in Western Canada. Transformational light oil pool discovery. Multiyear drilling inventory (oil and gas) that has been de-risked with current recompletion operations. Gas recompletions extremely economic at very low gas prices; 10 well recompletion inventory to be executed over the next 12 to 18 months. 21

22 MANAGEMENT Tim de Freitas President & CEO Dorothy Else Executive VP Carrie Yuill VP Finance & CFO Greg Feltham VP Exploration Kavanagh Mannas VP Operations Yvonne McLeod Senior VP Engineering Rich Rowe VP Land BOARD OF DIRECTORS Robert Dales (Chairman) Dave Anderson Tim de Freitas Charle Gamba William Guinan (Corporate Secretary) Mike Kohut BANKS The Toronto-Dominion Bank ATB AUDITOR KPMG LLP LEGAL COUNSEL Borden Ladner Gervais LLP TRANSFER AGENT Alliance Trust Company RESERVE EVALUATORS Sproule and Associates Ltd. ANALYST COVERAGE Acumen Capital Trevor Reynolds Beacon Securities Kirk Wilson Clarus Securities Rob Pare Desjardins Jamie Kubik First Energy Cody Kwong Haywood Securities Darrell Bishop PI Financial Brian Purdy TD Securities Juan Jarrah CORPORATE OFFICE Suite 2700, th Avenue SW Calgary, AB T2P 3H5 T: (403)

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24 Reserves Category NPV 10% (M$) Oil (Mbbl) Liquids (Mbbl) Gas (MMcf) MBOE Developed Producing $ 103, ,501 13,642.2 Developed Non-Producing $ 14, ,354 2,238.4 Undeveloped $ 13, ,384 4,050.3 Total Proved $ 131, ,239 19,930.9 Probable $ 58, ,798 7,607.6 Total proved plus probable $ 190, ,037 27,538.5 Based on Dec 2016 Consensus Price Forecast (Sproule, McDaniel, GLJ) NET ASSET VALUE PER SHARE 10% NPV of 2P P&NG reserves, before tax ($000's) $ 190,031 Undeveloped land (1) ($000's) $ 20, YE Net Debt (Unaudited) ($000's) $ (32,465) Net asset value ($000's) $ 178,416 Common shares outstanding (000's) - basic 92,244 Common shares outstanding (000's) - diluted 98,437 Net asset value per share - basic $ 1.89 Net asset value per share - diluted $ 1.81 (1) Estimated at $110/acre Year Canadian Lt Sweet Crude 40 API ($C/Bbl) Western Canada Select 20.5 API ($C/Bbl) Alberta AECO-C ($C/MMBtu) Exchange Rate ($US/$C) 2017 $ $ $ 3.43 $ $ $ $ 3.17 $ $ $ $ 3.26 $ $ $ $ 3.67 $ $ $ $ 3.86 $ $ $ $ 3.97 $ $ $ $ 4.11 $ $ $ $ 4.23 $ $ $ $ 4.31 $ $ $ $ 4.41 $ $ $ $ 4.50 $ prices escalate at 2% thereafter 24

25 Foothills delivers highest rate oil wells and leading economics in the basin. Payout in years at C$40 C$80/bbl. Emerging oil play at IKM has the potential to deliver similar returns. IP (bbl/d); EUR (MBoe) IP90 (boe/d) CARDIUM PLAY BOOK (1) EUR (mboe) IRR Wells >50% Gas IRR Wells >50% Oil 50% 45% 40% 35% 30% 25% 20% 15% 10% 5% IRR (%) 0 0% STOLBERG (1,2) IP WELL POPULATION Lochend (78% liq) Garrington (85% liq) Ferrier (38% liq) CARDIUM DATA BY AREA (1) Willesden Wilson Crk Grn (45% liq) (71% liq) East Pembina (82% liq) Cent Pembina (85% liq) W Pembina 82% liq) Edson (44% liq) Kaybob (78% liq) Wapiti (45% liq) Stolberg (87% liq) IP90 (boe/d) IP 90% Liquids 78% 85% 38% 45% 71% 82% 85% 82% 44% 78% 45% 87% EUR (mboe) EUR % Liquids 44% 60% 23% 30% 46% 68% 74% 67% 33% 55% 27% 51% Cost ($mm) $2.9 $2.5 $2.9 $2.7 $2.2 $2.2 $2.4 $2.5 $2.5 $2.5 $2.9 $3.6 Sample Wells NPV10* ($mm) $(0.1) $0.2 $1.5 $0.8 $0.0 $0.7 $0.9 $0.7 $0.0 $1.4 $0.3 $2.3 IRR 9% 12% 25% 16% 10% 18% 19% 19% 10% 24% 13% 43% Breakeven WTI** $49 $45 $24 $36 $49 $40 $39 $40 $48 $34 $44 $31 Top Operators by Hz. Prod'n: Pengrowth Pengrowth Orlen Bellatrix Tamarack Bonterra ARC Lightstream Long Run TORC Long Run Manitok Lightstream Whitecap CNRL Penn West OMERS ARC Penn West Vermilion TORC Conoco Modern Petrus Orlen Exxon Petrus Lightstream Regent Whitecap Bellatrix Whitecap Successor Repsol Husky Direct Enrg. (1) TD Industry Note, June (2) Sample population includes wells that penetrated Cordel oil pool in , which lowers Stolberg average EUR and IP. 25

26 Reservoir Quality and Production Peak Prod. Rate (IP30, bbl/d) Peak Cal. Rate (IP90, BOE/d) EUR (Oil) vs EUR (BOE) %Oil Count Phi*h NARRAWAY 0.8 Berland , ,215 41% E Pembina ,252 96,838 72% Edson , ,529 19% Ferrier , ,236 27% Fir ,865 88,858 48% Harme , ,254 64% Kaybob , ,951 76% Lochend , ,923 57% Med River , ,519 50% N Pembina ,027 97,003 97% Notin-Carrot ,727 75,473 63% NW Pembina ,965 97,003 72% Pine Creek ,701 85,455 29% Rosevear , ,637 66% Will Grn , ,105 37% Wilson Ck ,724 91,258 59% Wapiti , ,149 61% Kakwa , ,387 13% Cordel-Stol , ,479 89% Stolberg , ,721 74% Initial Production (IP) and Total Oil and Associated Gas Produced Peak Prod. Rate (IP30, bbl/d) Peak Cal. Rate (IP90, BOE/d) Avg. Cal. Rate (IP30, bbl/d) EUR (Oil) vs EUR (BOE) %Oil Count Cordel-Stol , ,479 89% 12.0 Stolberg (Oil) , ,721 74% 23.0 Berland , ,215 41% 19.0 Brown Ck ,406 21, % 2.0 E Pembina ,252 96,838 72% Edson (oil) , ,529 19% 50.0 Ferrier (oil) , ,236 27% Fir (Oil) ,865 88,858 48% 14.0 Harme (Oil) , ,254 64% Kakwa (Oil) , ,387 13% 11.0 Kaybob (Oil) , ,951 76% 38.0 Lochend (Oil) , ,923 57% Med River (Oil) , ,519 50% 73.0 N Pembina (Oil) ,027 97,003 97% N Smoky (Oil) ,546 63,088 44% 5.0 Notin-Carrot (Oil) ,727 75,473 63% 32.0 NW Pembina (Oil) ,965 97,003 72% Pine Creek (Oil) ,701 85,455 29% 13.0 Rosevear (Oil) , ,637 66% 35.0 Will Grn (Oil) , ,105 37% Wilson Ck (Oil) ,724 91,258 59% Wapiti (Oil) , ,149 61%

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28 Discovered more than 20 years ago. Peak production of 5,100 Bbls/d; individual wells with production potentially surpassing 1 MMBoe. Early wells offset vertical wells with approximately similar initial rates and cumulative production to Ikkuma s Cardium of the Northern Alberta Foothills. Comparable reservoir quality to Ikkuma s Northern Alberta Foothills Cardium, though not as complexly deformed. Stolberg Cardium 7,000 6,000 5,000 4,000 3,000 2,000 1,000 STOLBERG CARDIUM 5,100 Bbl/d 7,520 boe/d peak prod. - Jan-12 May-12 Sep-12 Jan-13 May-13 Sep-13 Jan-14 May-14 Sep-14 Jan-15 May-15 Sep-15 Jan-16 May-16 Oil (bbl/d) GOR (scf/bbl) 28

29 An example of a large resource captured through horizontal drilling in shallow bypass reservoirs: IP: bbl/d Discovery vertical well (1997), w5. IP Bbls/d. Produced 30 Mbbls. Source: Geoscout Source: Geoscout 30 X multiple of vertical vs. horizontal. IP: ~1,000 bbl/d Produced >200 Mbbls 52 API oil and 1 Bcf in 20 months. 600 bbl/d This well was not stimulated, and free-flowed to surface for all of its production history. 400 bbl/d 200 bbl/d Source: Geoscout Source: Geoscout 29

30 Summary (HZ Multiplier) IP-X EUR-X Elm/Wapiti South-OIL (all wells outside Wapiti Pool) Elm/Wapiti (near offsets) Stolberg Harme-Oil (32-3) Kaybob ( ) Pembina (45-11,12) gasy IKM Alberta Foothills Vertcal Well # ,000 Vertcal Well #2 75 n/a ,000 Use Elm/Wapiti near offset multlier 1, ,215 Vertical - HZ Well Multiplier: the Cardium Formation in Elmworth / Wapiti has the most similar reservoir characteristics, based on logs. On average, horizontal wells in Wapiti benefit from a 9.3x increase on IP, 6.8x increase on EUR when compared to near offset vertical wells. Elm/Wapiti-Oil (near offset to vertical well HZ Vert (one well), offset pool is conv. Wapit Peak Prod. EUR Peak Prod. Rate EUR bbl/d bbl bbl/d bbl Mean 1 well 36 17, ,072 S-Mean ,376 Median ,706 Count Std. Dev ,304 r² Peak (bbl/d) EUR (Mbb) Dist ,909 Min ,597 P ,742 P ,009 P ,356 P ,798 P ,508 P ,198 P ,284 P ,299 P ,579 P ,075.1 P ,580.3 P10 1, ,914.9 P1 1, ,411.9 Max 1, ,411.9 Elm/Wapiti South-OIL (all wells outside Wapiti Pool) HZ Vert (one well), offset pool is conv. Wapiti Peak Prod. EUR Peak Prod. Rate EUR bbl/d bbl bbl/d bbl Mean 1 well 36 17, ,597 S-Mean ,221 Median ,378 Count Std. Dev ,055 r² Dist Peak (bbl/d) EUR (Mbb) Min ,931 P ,435 P ,862 P ,901 P ,555 P ,471 P ,512 P ,009 P ,510 P ,017 P ,819.6 P ,838.9 P ,529.8 P ,703.5 Max 1, ,411.9 The average of the two Cardium wells within the foothills trend was used for an expected vertical IP of 149 Bopd. Applying the Wapiti HWM to this number yields an expected horizontal IP of 1378 Bopd and 212,215 Bbls EUR. HEAVILY RISKED well IP of Bopd were used for modelling. Note: Stolberg average well multiplier is higher due to the natural fracture system in place (unstimulated vs stimulated). 30