February 2018
A Confluence of Positive Factors BLACKBIRD LIFE CYCLE MARKET CONDITIONS BLACKBIRD VALUE PROPOSITION Social License LARGE, CONTIGUOUS LAND BLOCK 134 GROSS SECTIONS Alberta Jurisdiction CASH ON HAND $21.3 MM (1) DELINEATED DRILLING SUCCESS Area Activity EGRESS AND MARKET ACCESS Operating History = Primary value drivers = Secondary value drivers Notes: (1) Working capital surplus as at October 31, 2017. 2
All Eyes on the Pipestone Corridor The Highest Value Montney A&D Directly Offsets Blackbird Industry Activity is Exploding in the Pipestone Corridor Seven Generations acquisition of Paramount Kakwa Sets a new high for undeveloped Montney land at $6.1 MM per section Paramount acquisition of Apache Transaction provides benchmark for Montney land value in the region Anticipated POU drilling will delineate the liquids rich corridor Plans for >300 well drilling program with growth potential to 76,000 boe/d (>30% condensate) Industry plans a major infrastructure investment at Pipestone through 2020 Five sour processing facilities & various condensate pipelines already sanctioned or in FEED stages E&P s require scale to strike a long term take-or-pay with midstreamers consolidation is upcoming NuVista plans >120 wells on 11 sections three miles west of Blackbird stacked pay boosts full-cycle economics Encana s Cube development reduces costs and improves economic recovery factors The Cube will become the industry standard for stacked pay development, Doug Suttles, Encana, Pres. & CEO Blackbird Pipestone One of the Most Actively Drilled Corridors in Canada New Blackbird drill to the north will validate the northern Wapiti lands Pipestone has been actively licensing and spudding wells Five (1.2 net) non-operated Blackbird wells extend the fairway to the east Velvet s 13-15-70-4W6 well, confirms the volatile oil window is prospective, validating all of Blackbird s lands Paramount s acquisition of Apache Montney lands 14-30 Joint Interest 02/2-20 Recompletion 3-27 New Drill 15-21 Re-completion 2-28 New Drill 2-20 Re-completion 13-4 Joint Interest Eastern Gathering System 3
The Pipestone Corridor Escalating Activity Kelt 04-01(3) 1,567 boe/d (64% oil, 20% NGLs and 16% gas) over a 5 day test CNRL 12-2 550 Bbls/MMcf BBI 02/6-26, Upper Peak 48hr rate 924 boe/d (CGR 591 bbls/mmcf)(4) Pipestone 5-26 222 Bbls/MMcf (1) BBI 2-28, Middle Peak 48hr rate 721 boe/d (CGR 251 bbls/mmcf) (4) Pipestone 6 drilled NuVista 13-27 >100 Bbls/MMcf(2) 6 MMcf/d and 600 bbls/d of condensate over final 24 hours of test Pipestone 13-22 Upper, 72 hr Test 3.6 MMcf/d & 1000 Bbls condensate/day(1) CNRL 13-7, Middle 299 Bbls/MMcf, (1) 15-11 & 4-28 Montney Hz Drilled 2-28 02/6-26 15-21 BBI 15-21, Upper Peak 48hr rate 729 boe/d (CGR 257 bbls/mmcf) (4) BBI 2-20, Middle 72hr test rate 1,163 boe/d (CGR 454 bbls/mmcf) (4) 1-20 2-20 BBI 1-20, Upper 48hr test rate 1,054 boe/d (CGR 192 bbls/mmcf) (4) Shell >60 Montney Hz Licenced >40 Drilled Mid Montney 15-12-67-5W6 IP 180: CGR Avg 227 Bbls/MMcf @ 2.5 MMcf/d Notes: (1) Public data from IHS AccuMap; (2) NuVista September 2017 Corporate Presentation (3) Kelt press release October 6, 2017 (4) See notes on initial production results on page 10 of this presentation. The Company cautions that short-term test rates are not necessarily indicative of long-term well or reservoir performance or of ultimate recovery. See Initial Production Rates and Short Term Test Rates" at the end of this presentation. 4
The Pipestone Liquids-Rich Corridor BBI Mapping of Upper Montney Condensate Corridor (2) Encana s Mapping of Liquids-Rich Corridor (1) ~60 sections in Encana s Super Condensate Corridor (2) BBI Mapping of Middle Montney Condensate Corridor (2) Source: (1) Encana May 17, 2016 Montney Investor Event Presentation (slide 49); (2) Internal mapping by Blackbird; Represents analogous information. See Analogous Information in Advisories. 5
The Pipestone Liquids-Rich Corridor 1 W 2 02/10-08-070-07W6/0 00/11-02-071-08W6/0 02/01-03-072-09W6/0 E 00/08-25-070-07W6/0 KB: 684.6 m RR: 2015-10-26 TD: 2586.5 m [TVD] FormTD: MNTN Mode: Abd W hip Fluid: N/A BLACKBIRD ELM 10-8-70-7 KB: 694.7 m RR: 1998-01-24 TD: 2550.0 m [TVD] FormTD: BLLY Mode: Susp Fluid: Gas ECA ELM 11-2-71-8 KB: 831.5 m RR: 2011-03-30 TD: 2743.4 m [TVD] FormTD: BLLY Mode: Abd Zone Fluid: N/A CNRL ALBRT 1-3-72-9 5 4 3 RR: 1996-11-30 KB: 670.9 m FormTD: BLLY TD: 2462.0 m [TVD] Fluid: N/A Mode: Abnd AECOG (W ) ELMWORTH 8-25-70-7 2200 2200 2225 2250 2250 ( -1579.1 ) 2175 2175 ( -1521.9 ) 2200 2125 2125 2150 2150 ( -1496.9 ) 2200 ( -1546.9 ) 2225 ( -1571.9 ) 2225 2150 2250 2175 2275 2275 2275 ( -1604.1 ) 2300 2400 ( -1715.4 ) 2300 ( -1629.1 ) 2425 2425 ( -1740.4 ) 2200 2425 2375 2375 ( -1680.3 ) 02/626 Hz BBI 02/6-26 2400 2400 ( -1655.3 ) 02/220 Hz 2575 2575 ECA 14-30 14-30 Hz 12-25 Hz 2375 CNRL 12-25 2375 ( -1690.4 ) BBI 02/2-20 2550 2550 ( -1718.5 ) 2375 2375 2525 ( -1630.3 ) 2525 ( -1693.5 ) 2450 ( -1765.4 ) 6-26 Hz ( -1654.1 ) ( -1679.1 ) 2375 2375 ( -1704.1 ) 2400 2400 ( -1729.1 ) 2475 2475 2425 2425 2425 ( -1730.3 ) BBI 6-26 2600 ( -1768.5 ) 2475 ( -1790.4 ) 3-17 Hz 2275 2275 ( -1621.9 ) 2300 2250 2250 2250 ( -1596.9 ) 2300 ( -1646.9 ) Non-operated 3-17 2625 2625 2300 2-20 Hz 2225 BBI 2-20 2450 2450 2400 2400 ( -1705.3 ) 2600 2600 2400 2575 ( -1743.5 ) ( -1671.9 ) 2500 ( -1815.4 ) 2650 2650 2275 2450 ( -1755.3 ) 2500 2500 2450 2450 2625 ( -1793.5 ) 2375 2525 2525 ( -1840.4 ) 2300 2525 2475 2475 ( -1780.3 ) 2675 2675 2475 2650 ( -1818.5 ) 2550 ( -1865.4 ) 1 2400 W 2550 2550 2500 2500 ( -1805.3 ) 2700 2500 2675 ( -1843.5 ) 2700 2700 ( -1868.5 ) 2425 PACKER 2425 Lower Montney 2125 ( -1471.9 ) 2225 2300 2225 ( -1554.1 ) ( -1665.4 ) 2500 ( -1668.5 ) 2525 2550 2300 ( -1605.3 ) 2200 ( -1529.1 ) 2500 2500 2300 Doig Upper Montney Middle Montney 2275 2100 ( -1446.9 ) 2475 ( -1643.5 ) CEMBRP 2425 ( -1754.1 ) CEMBRP 2 Consistent geology across multiple intervals Note: Sourced from Accumap. 3 4 ACIDSQ 2575 ( -1890.4 ) 2525 ( -1830.3 ) 2575 2525 JET 2575 ACIDSQ 2525 Belloy 200 meters KB: 653.1 m RR: 1981-09-23 TD: 3651.0 m [TVD] FormTD: IRTN Mode: Abd Zone Fluid: Gas CEQUEL GOLDCK 6-17-70-5 ( -1640.4 ) 2475 2475 2275 00/06-17-070-05W6/0 2275 ( -1580.3 ) ( -1696.9 ) JET 5 E 6
Blackbird s Pipestone Resource Blackbird s Lands with Proved Reserves Booked Blackbird s Lands with Proved + Probable Reserves Booked 10.25 sections booked 16.5 sections booked (9.0% of land booked) (14.4% of land booked) 1P Reserves: 28,578 mboe 2P Reserves: 54,372 mboe 1P NPV10: $167 million 2P NPV10: $395 million Reserves Booked in Only Two of Four Highly Prospective Intervals Note: From Blackbird s July 31, 2017 reserve report prepared by Blackbird s independent reserves evaluator, McDaniel and Associates Consultants Ltd. 7
Development and Delineation Program Northern Multi-Interval Delineation Block 11 7 6 3 4 8 10 March Test 2 1 5 Western Development Block 9 12 BBI Producing Wells BBI Active Operations BBI Proposed Locations Eastern Multi-Interval Delineation Block 15 16 13 14 Producing Wells 1 2 3 4 5 6 7 8 9 6-26-70-7W6 (Middle) Tied-in/producing 5-26-70-7W6 (Upper) Tied-in/producing 2-20-70-7W6 (Middle) Tied-in/producing 102/2-20-70-7W6 (Upper) Tied-in/producing (recompletion) 02/6-26-70-7W6 (Upper) Tied-in/producing 15-21-70-7W6 (Upper) Tied-in/producing (recompletion) 2-28-70-7W6 (Middle) Tied-in/producing 1-20-70-7W6 (Upper) Tied-in/producing 2-20-70-6W6 (Middle) Tested; tie-in pending Active Operations 10 11 12 13 14 15 16 3-27-71-7W6 (Upper) Test results before the end of March 14-30-70-7W6 (Upper) Non-op: drilled, completed, tested 13-04-70-6W6 (Middle) Non-op: drilled, completed, tested 3-17-70-5W6 (Middle) Non-op: drilled, completed, tested 9-20-70-5W6 (Middle) Non-op: drilled, completed, tested 13-13-70-6W6 (Middle) Non-op; drilled, completed, tested 1-06-70-5W6 (Middle) Non-op; drilled, completed, tested 8
Current Well Summary 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 Well Operated or Non- Operated Working Interest (%) Montney Interval Measured Depth (meters) Lateral Length (meters) Number of Intervals Proppant (tonnes) 6-26-70-7W6 Operated 100 Middle 4,734 2,052 51 2,805 Tied-in / producing 5-26-70-7W6 Operated 100 Upper 4,621 1,951 49 2,695 Tied-in / producing 2-20-70-7W6 Operated 100 Middle 4,660 2,008 70 2,223 Tied-in / producing 102/2-20-70-7W6 Operated 100 Upper 4,598 2,049 33 1,650 Tied-in / producing 02/6-26-70-7W6 Operated 100 Upper 4,808 2,103 42 3,193 Tied-in / producing 15-21-70-7W6 Operated 100 Upper 4,120 1,300 24 3,170 Tied-in / producing 2-28-70-7W6 Operated 100 Middle 4,942 1,977 46 3,521 Tied-in / producing 1-20-70-7W6 Operated 100 Upper 4,590 2,012 42 4,040 Tied-in / producing 2-20-70-6W6 Operated 100 Middle 4,885 2,256 36 4,008 Tested; tie-in pending 3-27-71-7W6 Operated 100 Upper 4,604 2,200 59 4,500 Test results before the end of March 14-30-70-7W6 Non-Operated 17.9 Upper 5,350 2,861 95 5,053 Drilled, completed and tested 13-04-70-6W6 Non-Operated 37.5 Middle 5,615 3,056 75 3,682 Drilled, completed and tested 3-17-70-5W6 Non-Operated 20 Middle 5,320 2,876 75 3,605 Drilled, completed and tested 9-20-70-5W6 Non-Operated 24 Middle 5,260 2,857 75 3,591 Drilled, completed and tested 13-13-70-6W6 Non-Operated 20 Middle 4,720 2,233 75 3,565 Drilled, completed and tested 1-06-70-5W6 Non-Operated 20 Middle 5,012 2,515 100 3,687 Drilled, completed and tested Status 9
Production (boe/d) Recent IP30 and Test Results IP30 (1)(2)(3)(4) Well Condensate (bbl/d) Natural Gas (mcf/d) NGLs (bbl/d) CGR (5) (bbls/mmcf) Total (boe/d) % Load Water Recovered (6) Lateral Length (meters) 02/6-26-70-7W6 (Upper Montney) 2-28-70-7W6 (Middle Montney) 15-21-70-7W6 (Upper Montney) 475 1,076 20 460 674 37% 2,103 300 1,881 24 172 636 24% 1,977 289 1,424 18 216 543 14% 1,300 1,400 1,200 1,000 800 Recent Test Results (1)(2)(3)(4) Natural Gas (boe/d) NGLs (bbl/d) Condensate (bbl/d) 192 bbls/mmcf (5) 591 bbls/mmcf (5) 251 bbls/mmcf (5) 257 bbls/mmcf (5) 454 bbls/mmcf (5) 600 400 200 0 02/6-26-70-7W6* (Upper Montney) 2-28-70-7W6* (Middle Montney) 15-21-70-7W6* (Upper Montney) 1-20-70-7W6** (Upper Montney) 2-20-70-6W6*** (Middle Montney) Notes: The Company cautions that short-term test rates are not necessarily indicative of long-term well or reservoir performance or of ultimate recovery. See Initial Production Rates and Short Term Test Rates" at the end of this presentation. (1) Production from these wells has been restricted at times due to third party processing capacity limitations and water injection limitations; (2) Numbers may not add due to rounding; (3) All disclosed production rates and volumes are presented net of any load water; (4) All volumes are based on field estimated production data; (5) CGR includes condensate and NGL production; (6) Load water is not included in any of the other volumes reported; *Represents peak 48 hour rate over initial 30 days on production; **Represents production over the final 48 hours over an 11 day test; *** Represents production over the final 72 hours of an 10 day production test. 10
2017/2018 Moving Forward with a Clear Path Development Commercialization of Stage Reinforces the teams innovative approach New/enhanced GHA(s) Multiple binding Gas Handling Agreements 02/6-26 Completed and On-Stream 02/2-20 On-Stream 02-28 Completed and On-Stream 15-21 Recompleted and On-Stream 2-20-70-6W6 Recompletion 01-20 Completion Test results expected Mar 2018 3-27 Completion SEPTEMBER OCTOBER NOVEMBER DECEMBER JANUARY FEBRUARY INCREASING CORRIDOR MOMENTUM Significant industry well activity Five additional sour gas processing facilities and/or expansions planned 11
Processing Capacity (mmcf/d) Tidewater Agreement Sets the Stage for Future Growth Long Term Growth Five year term with option to extend; provides long term processing solution for both north and south of the Wapiti River Lower Cost Producer Blackbird has the option to acquire up to a 20% working interest in the facility, which would significantly reduce processing fee s enabling Blackbird to become a lower cost producer Enhanced Liquids Value Deep cut capability will allow Blackbird to obtain premium pricing for ethane, propane and all NGLs 35 30 25 20 15 Strategic Fit Provides solution for processing, sweet gas storage and fuel gas needs; both companies have significant business interest in the Grande Prairie area 10 5 0 Expected on-stream date of Q2 2019 Q2Q3Q4Q1Q2Q3Q4Q1Q2Q3Q4Q1Q2Q3Q4Q1Q2Q3Q4Q1 2019 2020 2021 2022 2023 12
Meters Consistent Decrease in Drill times 0 1,000 Blackbird Days vs. Depth 46.3 to 17.5 days (62% improvement) 2,000 3,000 4,000 6-26 6-26 in in 46.3 46.3 Days Days 5,000 3-27 in 17.5 Days 0 5 10 15 20 25 30 35 40 45 50 Days 13
Completion Optimization 20 Days 20 Days STAGE Completions Sliding Sleeve Completion Program #1 (5-26 and 6-26) Plug & perf cluster Slickwater ~2,700 tonnes of proppant 1.4 tonnes / meter of proppant 40 meter cluster spacing Completion Program #2 (2-20) Sliding Sleeve CO2 (largest in N.A.) ~2,223 tonnes of proppant 1.1 tonnes/ meter proppant 28.5 meter spacing 6.5 Days STAGE Generation Four 8620 (2-28) Sliding Sleeve Slickwater ~3,521 tonnes of proppant 1.8 tonnes/ meter proppant 40 meter spacing 5.2 Days STAGE Generation Four (3-27) Sliding Sleeve Slickwater ~4,500 tonnes of proppant ~2.0 tonnes / meter proppant ~37 meter spacing Higher Tonnage + Reduced Pump Time = Increased EUR and NPV 14
Value Delineation Curve / Acceleration Value $250 mm $2 mm BBI: 0 114.5 net sections 20 260 wells in corridor CGR s > 300 Bbls/MMcf (1) D&C $10mm $5.5mm Innovation: Stage NPV EUR 3 years 2 years <1 year Near - Term High Risk Notes: (1) Based on regional test data. Time Initial Production Ramp Up BBI Pilot Plant 10 mmcf/d GHA with Tidewater $84.8 mm Raised The Next Steps High Impact Development and Delineation Program Increased Processing / Takeaway Production Growth Through Expanded Egress Continued Land Aggregation Lower Risk 15
Corporate Social Responsibility Corporate Social Responsibility is critical to gain social license to operate in any community Tree Planting Program: focused on reclaiming boreal forest and replacing trees we take down; Planted 101,579 trees to date! Thank you Cormark, Pareto, TD, BMO, Scotia, Laurentian, & Jett Capital for contributing towards the tree planting program Goal: 200,000 trees Movement to reduce flare volumes Reduction in water usage through technology Boring vs. cutlines Mitigation of traffic impact Extensive community consultation Noise mitigation Our plan gives us a significant competitive advantage as we develop our resource this is also the right way to do business 16
Corporate Snapshot Common Share Trading Symbol Warrant Trading Symbol Shares Basic Fully Diluted Insider Holdings (1) Market Capitalization 52 Week Range (2/12/2018).WT Share Price (2/12/2018) $0.31 Cash (2) Gross Acreage Net Acreage ~748 mm ~963 mm ~18% ~$232 mm ~$21 mm $0.295 - $0.73 134 sections (85,760 acres) 114.5 sections (73,280 acres) Notes: (1) Includes shares owned in third party portfolio that is managed by board member. (2) Working capital surplus as at October 31, 2017. 17
Appendix: IP 30, IP60, IP90 IP30 RESULTS (1) IP60 RESULTS (1) IP90 RESULTS (1) Well Montney Interval Raw Gas (2) Sales Gas (3) Condensate (3) NGLs (3) Total Liquids (3) Total Sales (3) CGR C5+/Raw (mmcf/d) (mmcf/d) (bbls/d) (bbls/d) (bbls/d) (boe/d) (bbls/mmcf) 5-26-70-7W6 Upper 1.37 1.31 293 19 312 530 214 2-20-70-7W6 Middle 2.15 1.85 274 21 295 604 127 102/2-20-70-7W6 (4) Upper 0.58 0.49 69 6 75 157 119 6-26-70-7W6 Middle 0.68 0.59 111 9 120 218 163 Notes:(1) First 720 hours of production excluding third party gas processing plant shut-downs of approximately 33 days and other periods where the wells were shut-in. (2) Based on fieldestimated production data. (3) Based on actual sales data. (4) Based on camera run performed, management estimates that this well was producing through a limited number of stages due to mechanical issues experienced in the wellbore during completion operations. Management is unable to determine the number of producing stages. Management believes that these results may not be indicative of the well s production potential. Well Montney Interval Raw Gas (2) Sales Gas (3) Condensate (3) NGLs (3) Total Liquids (3) Total Sales (3) CGR C5+/Raw (mmcf/d) (mmcf/d) (bbls/d) (bbls/d) (bbls/d) (boe/d) (bbls/mmcf) 5-26-70-7W6 Upper 1.17 1.09 224 19 243 425 191 2-20-70-7W6 Middle 2.59 2.31 254 28 282 667 98 6-26-70-7W6 Middle 0.54 0.47 121 9 130 208 225 Notes:(1) First 1,440 hours of production excluding third party gas processing plant shut-downs of approximately 33 days and other periods where the wells were shut-in. (2) Based on field-estimated production data. (3) Based on actual sales data. Well Montney Interval Raw Gas (2) Sales Gas (3) Condensate (3) NGLs (3) Total Liquids (3) Total Sales (3) CGR C5+/Raw (mmcf/d) (mmcf/d) (bbls/d) (bbls/d) (bbls/d) (boe/d) (bbls/mmcf) 5-26-70-7W6 Upper 1.17 1.08 200 20 220 400 171 2-20-70-7W6 Middle 2.72 2.45 245 31 276 684 90 Notes:(1) First 2,160 hours of production excluding third party gas processing plant shut-downs of approximately 33 days and other periods where the wells were shut-in. (2) Based on field-estimated production data. (3) Based on actual sales data. 18
Advisories Forward Looking Statements This presentation contains certain information and statements ("forward-looking statements") that constitute forward-looking information within the meaning of applicable Canadian securities laws. Forward-looking statements relate to future results or events, are based upon internal plans, intentions, expectations and beliefs, and are subject to risks and uncertainties that may cause actual results or events to differ materially from those indicated or suggested therein. All statements other than statements of current or historical fact constitute forward-looking statements. Forward-looking statements are typically, but not always, identified by words such as "anticipate", "estimate", "expect", "intend", "forecast", "continue", "propose", "may", "will", "should", "believe", "plan", "target", "objective", "project", "potential" and similar or other expressions indicating or suggesting future results or events. Forward-looking statements are not promises of future outcomes. There is no assurance that the results or events indicated or suggested by the forward-looking statements, or the plans, intentions, expectations or beliefs contained therein or upon which they are based, are correct or will in fact occur or be realized (or if they do, what benefits the Company may derive therefrom). In particular, but without limiting the foregoing, this presentation contains forward-looking statements pertaining to: any information that is in the nature of guidance or a forecast, and underlying assumptions; industry activity and transactions in the Pipestone Corridor, and the relevance to Blackbird; the attributes and potential of the Montney formation; the multi-interval potential of Company's lands, including the number of prospective Montney intervals; proposed drilling locations; validation of the Company's lands through both internal and third party drilling activity; timing for test results from wells drilled and completed but not yet tested; timing for pending tie-in of existing wells; anticipated cost reductions and NGL recovery improvements from the processing agreement with Tidewater Midstream and Infrastructure Ltd.; benefits to be realized from completion optimization efforts and initiatives; plans with respect to development and delineation drilling, increased processing, production growth and land aggregation; and competitive advantage realized from corporate social responsibility initiatives. With respect to the forward-looking statements contained in this presentation, Blackbird has assessed material factors and made assumptions regarding, among other things: future commodity prices and currency exchange rates, including consistency of future oil, natural gas liquids (NGLs) and natural gas prices with current commodity price forecasts; the Company's continued ability to obtain qualified staff and equipment in a timely and cost-efficient manner; the ability to successfully apply to Blackbird properties the infrastructure and facility design concepts applied elsewhere in its Pipestone / Elmworth Project; the predictability of future results based on past and current experience; the predictability and consistency of the legislative and regulatory regime governing royalties, taxes, environmental matters and oil and gas operations, both provincially and federally; the Company's ability to successfully market its production of oil, NGLs and natural gas; the timing and success of drilling and completion activities (and the extent to which the results thereof meet expectations); the Company's future production levels and amount of future capital investment, and their consistency with the Company's current development plans and budget; future capital expenditure requirements and the sufficiency thereof to achieve the Company s objectives; the successful application of drilling and completion technology and processes; the applicability of new technologies for recovery and production of the Company's reserves and other resources, and their ability to improve capital and operational efficiencies in the future; the recoverability of the Company's reserves and other resources; the Company s ability to economically produce oil and gas from its properties and the timing and cost to do so; the performance of both new and existing wells; future cash flows from production; future sources of funding for the Company's capital program, and its ability to obtain external financing when required and on acceptable terms; future debt levels; geological and engineering estimates in respect of the Company's reserves and other resources; the accuracy of geological and geophysical data and the interpretation thereof; the geography of the areas in which the Company conducts exploration and development activities; the timely receipt of required regulatory approvals; the access, economic, regulatory and physical limitations to which the Company may be subject from time to time; and the impact of industry competition. Information and statements regarding the Company's reserves also are forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves exist in the quantities predicted or estimated and can be profitably produced in the future. The forward-looking statements contained herein reflect management's current views, but the assessments and assumptions upon which they are based may prove to be incorrect. Although Blackbird believes that its underlying assessments and assumptions are reasonable based on currently available information, undue reliance should not be placed on forward-looking statements, which are inherently uncertain, depend upon the accuracy of such assessments and assumptions, and are subject to known and unknown risks, uncertainties and other factors, both general and specific, many of which are beyond the Company's control, that that may cause actual results or events to differ materially from those indicated or suggested in the forward-looking statements. Such risks, uncertainties and other factors are discussed in the Company s current annual information form, annual and interim management s discussion and analysis, and other documents filed by it from time to time with securities regulatory authorities in Canada, copies of which are available electronically on SEDAR at www.sedar.com, and include, but are not limited to: volatility in market prices and demand for oil, NGLs and natural gas and hedging activities related thereto; general economic, business and industry conditions; variance of the Company's actual capital costs, operating costs and economic returns from those anticipated; the ability to find, develop or acquire additional reserves and the availability of the capital or financing necessary to do so on satisfactory terms; risks related to the exploration, development and production of oil and natural gas reserves and resources; negative public perception of oil and natural gas development and transportation, hydraulic fracturing and fossil fuels; actions by governmental authorities, including changes in government regulation, royalties and taxation; potential legislative and regulatory changes; the rescission, or amendment to the conditions of, groundwater licenses of the Company; management of the Company's growth; the ability to successfully identify and make attractive acquisitions, joint ventures or investments, or successfully integrate future acquisitions or businesses; the availability, cost or shortage of rigs, equipment, raw materials, supplies or qualified personnel; adoption or modification of climate change legislation by governments; the absence or loss of key employees; uncertainty associated with estimates of oil, NGLs and natural gas reserves and resources and the variance of such estimates from actual future production; dependence upon compressors, gathering lines, pipelines and other facilities, certain of which the Company does not control; the ability to satisfy obligations under the Company's firm commitment transportation arrangements; the uncertainties related to the Company's identified drilling locations; the high-risk nature of successfully stimulating well productivity and drilling for and producing oil, NGLs and natural gas; operating hazards and uninsured risks; the possibility that the Company's drilling activities may encounter sour gas; execution risks associated with the Company's business plan; failure to acquire or develop replacement reserves; the concentration of the Company's assets in the Pipestone / Elmworth Project area; unforeseen title defects; aboriginal claims; failure to accurately estimate abandonment and reclamation costs; the potential for development and exploratory drilling efforts and well operations to be unprofitable or not achieve targeted returns; horizontal drilling and completion technique risks and failure of drilling results to meet expectations for reserves bookings or production; limited intellectual property protection for operating practices and dependence on employees and contractors; third party claims regarding the Company's right to use technology and equipment; expiry of certain leases for the undeveloped leasehold acreage in the near future; failure to realize the anticipated benefits of acquisitions or dispositions; failure of properties currently held or acquired in the future to produce as projected and inability to accurately determine reserve and resource potential, identify liabilities associated with acquired properties or obtain protection from sellers against such liabilities; changes in the application, interpretation and enforcement of applicable laws and regulations; restrictions on drilling intended to protect certain species of wildlife; potential conflicts of interests; actual results differing materially from management estimates and assumptions; seasonality of the Company's activities and the Canadian oil and gas industry; alternatives to and changing demand for petroleum products; extensive competition in the Company's industry; lower oil, NGLs and natural gas prices and higher costs; failure of 2D and 3D seismic data used by the Company to accurately identify the presence of oil and natural gas; risks relating to commodity price hedging instruments; terrorist attacks or armed conflict; cyber security risks, loss of information and computer systems; inability to dispose of non-strategic assets on attractive terms; security deposits required under provincial liability management programs; reassessment by taxing authorities of the Company's prior transactions and filings; variations in foreign exchange rates and interest rates; third party credit risk including risk associated with counterparties in risk management activities related to commodity prices and foreign exchange rates; sufficiency of insurance coverage; potential litigation; variation in future calculations of non-ifrs measures; sufficiency of internal controls; breach of agreements by counterparties and potential enforceability issues in contracts; impact of expansion into new activities on risk exposure; inability of the Company to respond quickly to competitive pressures; and the risks related to the common shares and warrants that are publicly traded. This list is not exhaustive. The forward-looking statements contained in this presentation are made as of the date hereof and Blackbird assumes no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, unless required by applicable securities laws. All forward-looking statements herein are expressly qualified by this advisory. 19
Advisories Third Party Information This presentation contains statistical data, market research and industry forecasts that were obtained from government or other industry publications and reports or are based on estimates derived therefrom and management s knowledge of, and experience in, the markets in which Blackbird operates. Government and industry publications and reports generally indicate that they have obtained information from sources believed to be reliable, but do not guarantee its accuracy or completeness. Often, such information is provided subject to specific terms and conditions limiting the liability of the provider, disclaiming any responsibility therefor, and/or limiting a third party s ability to rely thereon. No author of any such publication or report has consulted for or advised or counselled Blackbird or is in any way associated with the Company. Further, organizations that are proponents of the Canadian oil and gas industry may present information in a manner that is different from, and potentially more favourable to the industry than, information presented by an entirely independent source. Actual outcomes may vary materially from those forecast in such reports or publications, and the prospect for material variation can be expected to increase as the length of the forecast period increases. Market and industry data is subject to variation and cannot be verified due to limits on the availability and reliability of data inputs, the voluntary nature of the data gathering process, and other limitations and uncertainties inherent in any survey. Blackbird has not verified any data from third party sources referred to in this presentation or assessed any underlying assumptions relied upon by such sources. Reserves Data Disclosure Figures provided in this presentation as to the Company's reserves volumes and net present value of future net revenue attributable thereto are estimates of such volumes and values as at July 31, 2017 based on an evaluation by McDaniel & Associates Consultants Ltd. ("McDaniel"), Blackbird's independent qualified reserves evaluator, dated November 23, 2017 and effective July 31, 2017. McDaniel's evaluation was in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and, pursuant thereto, the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook"). Information in this presentation regarding the Company's estimated reserves, net present value of related future net revenue, and production is expressed on a net Company interest basis, being its working interest (operating and non-operating) share after deduction of royalty obligations plus any royalty interest. Estimates of future net revenue are after deduction of forecasted royalties, operating costs, estimated well abandonment and reclamation costs and estimated future development costs, but without any provision for interest costs, debt service charges or general and administrative expenses. Reserves volumes attributed to the Company's properties and related future net revenue are estimates only. There is no assurance that the estimated reserves can or will be recovered or that estimated future net revenues will be realized. Actual reserves may be greater or less than those estimated, and the difference may be material. Similarly, estimated net present values of related future net revenue attributed to reserves do not represent fair market value of those reserves. There is no assurance that the forecast prices and cost assumptions applied in evaluating the reserves and estimating related future net revenue will be attained, and variances between actual and forecast prices and costs may be material. The determination of oil and gas reserves involves estimating subsurface accumulations of oil, NGLs and natural gas that cannot be exactly measured. The preparation of estimates is subject to an inherent degree of associated risk and uncertainty, including factors that are beyond the Company's control. The estimation and classification of reserves is a complex process involving the application of professional judgment combined with geological and engineering knowledge to assess whether specific classification criteria have been satisfied. It requires significant judgments based on available geological, geophysical, engineering, and economic data as well as forecasts of commodity prices and anticipated costs. As circumstances change and additional data becomes available, whether through the results of drilling, testing and production or from economic factors such as changes in product prices or development and production costs, reserves estimates also change. Revisions may be positive or negative. Estimates of reserves and related future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. Initial Production Rates and Short-Term Test Rates This presentation includes disclosure on initial production (IP) rates for certain wells over 30-day (IP30), 60-day (IP60) and 90-day (IP90) measurement periods. It also discloses test rates of production for certain wells over short periods of time, which are preliminary and not determinative of the rates at which those or any other wells will commence production and thereafter decline. Initial production rates and short-term test rates are not necessarily indicative of long-term well or reservoir performance or of ultimate recovery. Although such rates are useful in confirming the presence of hydrocarbons, they are preliminary in nature, are subject to a high degree of predictive uncertainty as a result of limited data availability, and may not be representative of stabilized on-stream production rates. Production over a longer period will also experience natural decline rates, which can be high in the Montney play and may not be consistent over the longer term with the decline experienced over an initial production period. Initial production or test rates may also include recovered "load" fluids used in well completion stimulation operations. Actual results will differ from those realized during an initial production period or short-term test period, and the difference may be material. Oil and Gas Measures Barrels of Oil Equivalent This presentation discloses certain production information on a barrels of oil equivalent ("boe") basis with natural gas converted to barrels of oil equivalent using a conversion factor of six thousand cubic feet of gas (mcf) to one barrel (bbl) of oil (6 mcf:1 bbl). Condensate and other NGLs are converted to boes at a ratio of 1 bbl:1 bbl. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is based roughly on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the Company's sales point. Although the 6:1 conversion ratio is an industry-accepted norm, it is not reflective of price or market value differentials between product types. Based on current commodity prices, the value ratio between crude oil, NGLs and natural gas is significantly different from the 6:1 energy equivalency ratio. Accordingly, using a conversion ratio of 6 mcf:1 bbl may be misleading as an indication of value. Reserves Categories The following definitions are derived from the COGE Handbook. "Reserves" are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on: (i) analysis of drilling, geological, geophysical and engineering data; (ii) the use of established technology; and (iii) specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according tothe degree of certainty associated with the estimates. "Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. "Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. References herein to: (i) "1P" means proved reserves; (ii) "2P" means proved plus probable reserves; and (iii) "NPV10" means, with respect to reserves, net present value of estimated future net revenue related to the reserves (before income taxes), discounted at 10% per year. 20
Advisories Oil and Gas Measures (continued) Gross versus Net Interests This presentation includes certain references to "gross" and "net" interests. The term "gross" means: (i) in relation to the Company's interest in production or reserves, its "company gross reserves", which are the Company's working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of the Company; (ii) in relation to wells, the total number of wells in which the Company has an interest; and (iii) in relation to properties, the total area of properties in which the Company has an interest. The term "net" means: (i) in relation to the Company's interest in production and reserves, the Company's working interest (operating and non-operating) share after deduction of royalties obligations, plus the Company's royalty interest in production or reserves; (ii) in relation to the Company's interest in wells, the number of wells obtained by aggregating the Company's working interest in each of its gross wells; and (iii) in relation to the Company's interest in a property, the total area in which the Company has an interest multiplied by the working interest owned by the Company. CGR References herein to "CGR" mean condensate/gas ratio and is expressed as a volume of condensate and NGLs (expressed in barrels) per million cubic feet (mmcf) of natural gas. Analogous Information Certain information in this presentation may constitute "analogous information" within the meaning of NI 51-101, including information relating to areas, wells or operations that are in geographical proximity to or believed to be on-trend with lands held by Blackbird and production information in respect of wells that are believed to be on trend with the Company's properties. Such information has been obtained from governmental or other public sources, regulatory agencies or other industry participants that are independent of Blackbird. The Company does not, though, know whether any such information contained herein that constitutes "analogous information" was prepared in accordance with the COGE Handbook or by a qualified reserves evaluator or auditor under NI 51-101, as applicable, and cannot verify its accuracy. While believed to be reliable, third party data relied upon by Blackbird may be in error. Management believes such information may be relevant to the Company's efforts to understand and predict reservoir characteristics of properties in which Blackbird may hold or intend to acquire an interest, and it is presented to help demonstrate the basis for the Company's business plans and strategies. There is, however, no assurance that the qualities, characteristics or results suggested by or inferred from analogous information are or will be similar to or otherwise representative of the qualities or characteristics of properties in which Blackbird has or intends to acquire an interest or the results that the Company may achieve or realize from any operations thereon. Such information is not, and should not be construed or relied upon as, an estimate or predictor of resource potential or future production levels. TSX Venture Exchange Disclaimer Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of the information contained in this presentation. 21
Blackbird Energy Inc. Blackbird Energy Inc. 400, 444 5 th Avenue SW Calgary, Alberta T2P 2T8 Garth Braun Chairman, CEO & President Tel: 403.699.9929 ext. 101 Cell: 403.500.5550 Email: gbraun@blackbirdenergyinc.com Allan Dixon Business Development Manager Tel: 403.699.9929 ext. 103 Cell: 587.227.7206 Email: adixon@blackbirdenergyinc.com 22