Continuing Success in Heavy Oil

Continuing Success in Heavy Oil Corporate Presentation March 2018

Advisory FORWARD-LOOKING STATEMENTS: This presentation contains certain forward-looking statements and forward-looking information (collectively referred to as "forward-looking statements") within the meaning of applicable Canadian securities laws. All statements other than statements of historical fact are forward-looking statements. Forward-looking statements typically contain words such as "anticipate", "believe", "plan", "continuous", "estimate", "expect", "may", "will", "project", predict, targeting, seek, intend, could, potential, scheduled, "should", outlook or similar words suggesting future outcomes. In particular, this presentation contains forward-looking statements pertaining to our business plans and strategies; potential heavy oil production growth potential of our Saskatchewan Thermal and Alberta Oil Sands asset groups on page 3 of the presentation; production potential, free cash flow estimates, reserve life and estimated net debt levels on page 4; estimated net revenues and free cash flow on page 6; the estimates Onion Lake reserves, sustaining capital and the estimated cash break-even price for the Onion Lake thermal project on page 6; projected debt levels in 2018 and 2019 and estimated peak debt levels during the phase 2 Onion Lake construction on page 7; future heavy oil production potential on page 8; estimated net present value of oil and gas reserves and contingent resources on page 9, estimated carbon tax impact on operating costs as well as the estimated oil prices to make the Onion Lake and Blackrod projects economic included on page 10 of the presentation, estimated IRR of the Onion Lake thermal project at US40/bbl and the potential for the Onion Lake reserves and resources supporting 20,000 barrels of oil per day for 20+ years and date of first oil and date of full production ramp-up from the Onion Lake expansion included on page 11; estimated production potential of 80,000+ bbl/d for the Blackrod SAGD project, estimated project life of the Blackrod SAGD oil sands project; estimated capital costs of $35,000/flowing bbl and the estimated economics of Blackrod at WTI oil prices of US$55+/bbl all on page 12; estimated Debt/Funds flow ratio for 2018 and 2019 on page 13; the 2018 Guidance on pages 14; estimated quantities of oil and gas reserves and contingent resources as well as the net present values of future net revenues from the reserves and contingent resources on page 20 and 21 of the presentation and the estimated capital spending for 2018 on page 22 of the presentation. The forward-looking statements in this presentation reflect certain assumptions and expectations by management. The key assumptions that have been made in connection with these forward-looking statements include the continuation of current or, where applicable, assumed industry conditions, the continuation of existing tax, royalty and regulatory regimes, commodity price and cost assumptions, the continued availability of cash flow or financing on acceptable terms to fund the Company s capital programs, the accuracy of the estimate of the Company s reserves and resource volumes and that BlackPearl will conduct its operations in a manner consistent with past operations. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect. By their very nature, forward-looking statements involve inherent risks and uncertainties which could cause actual results to differ materially from those contained in forward-looking statements. These factors include, but are not limited to, risks associated with fluctuations in market prices for crude oil, natural gas and diluent; risks related to the exploration, development and production of crude oil, natural gas and NGLs reserves; general economic, market and business conditions; substantial capital requirements; uncertainties inherent in estimating quantities of reserves and resources; extent of, and cost of compliance with, government laws and regulations and the effect of changes in such laws and regulations from time to time; the need to obtain regulatory approvals on projects before development commences; environmental risks and hazards and the cost of compliance with environmental regulations; aboriginal claims; inherent risks and hazards with operations such as fire, explosion, blowouts, mechanical or pipe failure, cratering, oil spills, vandalism and other dangerous conditions; potential cost overruns; variations in foreign exchange rates; diluent supply shortages; competition for capital, equipment, new leases, pipeline capacity and skilled personnel; uncertainties inherent in the SAGD bitumen and ASP recovery processes; credit risks associated with counterparties; the failure of the Company or the holder of licenses, leases and permits to meet requirements of such licenses, leases and permits; reliance on third parties for pipelines and other infrastructure; changes in royalty regimes; failure to accurately estimate abandonment and reclamation costs; inaccurate estimates and assumptions by management; effectiveness of internal controls; the potential lack of available drilling equipment and other restrictions; failure to obtain or keep key personnel; title deficiencies with the Company s assets; geo-political risks; risks that the Company does not have adequate insurance coverage; risk of litigation and risks arising from future acquisition activities. Further information regarding these risk factors and others may be found under "Risk Factors" in the Annual Information Form. Undue reliance should not be placed on these forward-looking statements. There can be no assurance that the plans, intentions or expectations upon which forward-looking statements are based will be realized. Actual results will differ, and the differences may be material and adverse to the Company and its shareholders. Furthermore, the forward-looking statements contained herein are made as of the date hereof, and the Company does not undertake any obligation, except as required by applicable securities legislation, to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained herein are expressly qualified by this cautionary statement. CONTINGENT RESOURCES: Contingent resources are defined in the COGE Handbook as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. There is no certainty that it will be commercially viable to produce any of the contingent resources. These volumes when totalled are the arithmetic sums of the Best Estimate Resources for Blackrod, Mooney and Onion Lake. Best estimate (P50) is a classification of estimated resources described in the COGE Handbook as being considered to be the best estimate of the quantity that will be actually recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the best estimate. Please refer to our Annual Information Form for a more detailed discussion of our contingent resources and the contingencies for each property. BOE s: All references to BOEs are based on a 6 to 1 conversion ratio. BOEs may be misleading, particularly if used in isolation. A BOE conversion of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. NON-GAAP MEASURES: This presentation uses the terms Adjusted Funds Flow which represent cash flow from operating activities (a GAAP measure) before asset abandonment costs and working capital adjustments. Free Cash Flow represents Adjusted Funds Flow less sustaining capital. The presentation also uses the term Estimated Net Revenues which represents revenues less royalties, transportation expenses and operating costs. Net debt is defined as long term debt less working capital. 2

Our Core Asset Groups Saskatchewan Thermal Ramping up to 12,000 bbl/d; 20,000+ bbl/d potential Top decile economics Growth can be internally funded AB SK Conventional Heavy 4,000 bbl/d Generates cash flow to cover corporate costs, including G&A, interest and sustaining capital AB SK Alberta Oil Sands 500 to 80,000+ bbl/d potential Piloted, development approvals received Funding/partner required AB SK 3

Why Invest in BlackPearl? Free cash flow generation Low sustaining capital requirements Thermal represents 60% of corporate production, going to 75%+ 80% of operating income from thermal is free cash flow Low decline, low cost production Thermal production has a 20+ year reserve life Thermal operating costs <$10/bbl All-in breakeven of C$27/bbl (including initial and sustaining capital) Financial/operating discipline Pilot all major projects before commercial development Net debt <1x cash flow in 2019 Growth potential Growing from 10,000 bbl/d to 16,000 bbl/d in 2019 100,000+ bbl/d potential from existing assets Share price appreciation potential Currently trading near PDP reserve values 4

Free Cash Flow Generation Saskatchewan thermal has best in class development economics Higher quality oil = better wellhead price Lower capital costs than AB oil sands Similar operating cost structure $200 $150 Estimated Net Revenues (1)(2) Based on 12,000 bbl/d $200 $150 Significant Free Cash Flow (1)(2) Based on $US60.00/bbl WTI oil price Net revenue Capital Production 20,000 15,000 $mm/yr $100 $mm $100 10,000 bbl/d $50 $50 5,000 $0 $40 WTI $50 WTI $60 WTI $70 WTI $0 2018 2019 2020 2021 2022 0 (1) Net revenues is a non-gaap measure. It represents revenues less royalties, transportation and operating costs (2) Estimated net revenues is based on 25% WCS heavy differential, FX of 0.80 and natural gas prices of $3.00/mcf 5

Low Decline, Low Cost Production Onion Lake thermal has reserves of 139 mm bbls Supports 20,000 bbl/d for over 20 years Low sustaining capital of $4-6/bbl Low cost operations. In 2017, thermal operating costs were <$10/bbl Non-energy costs $6.32/bbl Energy costs $3.56/bbl Full cycle costs $27/bbl Recycle ratio >2 Faster Regulatory Approval Saskatchewan Thermal Alberta Oil Sands Lower Capital Costs * Lower Operating Costs * Large Resource Size Long Life, Low Decline * Recent optimization efforts have lowered capital and operating costs in the oil sands. 6

Financial Discipline Fiscally disciplined with a strong balance sheet Cautious use of debt to fund investment Debt used to fund each phase of thermal at Onion Lake, expanded cash flow used for repayment Debt peaks at $130 140 mm during Onion Lake Phase 2 thermal expansion By the end of 2019 debt is expected to be <1x funds flow Debt history ($mm) 160 140 120 100 80 60 40 OL Thermal Phase 1 OL Thermal Phase 2 Potential OL Thermal Phase 3 20 0 Q1 14 Q2 14 Q3 14 Q4 14 Q1 15 Q2 15 Q3 15 Q4 15 Q1 16 Q2 16 Q3 16 Q4 16 Q1 17 Q2 17 Q3 17 Q4 17 Q1 18 Q2 18 Q3 18 Q4 18 Q1 19 Q2 19 Q3 19 Q4 19 7

Growth Potential Over the next 12 months we will grow from 10,000 bbl/d to 16,000 bbl/d In the next 10 years our existing projects have the potential to get us to over 40,000 bbl/d Development of future phases at Blackrod could take us over 100,000 bbl/d 50,000 BlackPearl Heavy Oil Production Profile (bbl/d) 45,000 40,000 35,000 30,000 25,000 20,000 15,000 10,000 5,000 0 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Base Primary Production Onion Lake Ph. 1 Onion Lake Ph. 2 Onion Lake future Blackrod Ph 1 8

Share Price Appreciation Potential Reserves (1) (NPV @ 10% BT) Risked Best Estimate Contingent Resources (NPV @ 10% BT) 1,900 5.65 1,500 4.46 1,500 4.46 $mm 1,000 500 Current Share Price $1.08/sh 2.97 1.49 $/share (4) $mm 1,000 500 2.97 1.49 $/share (4) 0-500 Net Debt PDP PNP PUD P2 0.00 (1.49) 0 0.00 Onion Lake and Blackrod Blackrod Phase 2 & 3 Phase 1 (2) and Mooney (3) (1) Source: Sproule reserve reports effective December 31, 2017; represents 2P reserve volumes of 162 MMboe (2) Source: Sproule development pending risked contingent resource (best estimate) reports effective December 31, 2017; represents risked contingent resource (best estimate) reports volumes of 193 MMboe (see Cautionary Statement on Contingent Resources in the Disclaimer section of the presentation) (3) Source: Sproule development on hold risked contingent resource (best estimate) reports effective December 31, 2017; represents risked contingent resource (best estimate) reports volumes of 447 MMboe risked contingent resource reports. Values in the development on hold category to be determined as we get closer to development (see Cautionary Statement on Contingent Resources in the Disclaimer section of the presentation) (4) Base on 336,512,240 common shares outstanding as of February 28, 2018 9

Company Risks Cost Risk Project capital has been dropping over the last few years in the oil sands as well as thermal projects in Saskatchewan. We have built two phases at Onion Lake on budget. Resource Risk Blackrod has a successful pilot and Phase 1 at Onion Lake is working as planned. Successful piloting and early performance are nearly always indicative of long term project performance. Peace River Mooney (primary, ASP flood) Athabasca Cold Lake Blackrod (SAGD) Onion Lake (primary, thermal) ALBERTA Political Risk Oil Sands Areas Even with carbon taxes @$50/tonne, this would result in <$2/bbl increase in operating costs Heavy Oil Price Risk Three new pipelines out of western Canada have been approved that will alleviate current capacity issues Hedging used to limit downside Economic Risk Onion Lake is economic @ US$40/bbl WTI and Blackrod is economic at US$55+/bbl WTI (with normalized differentials) SASKATCHEWAN 10

Onion Lake Thermal The Basics 2P Reserves - 139 mmbbl 11 API oil, will flow conventionally 10% IRR at US$40/bbl (25% WCS differential) Phase 1 (6,000 bbl/d) On production since Sept 2015 ISOR 2.5 Operating costs <$10/bbl Phase 2 (an additional 6,000 bbl/d) Sanctioned in February 2017 Completed in Q1 2018 Built on budget and ahead of schedule First oil expected in Q2 2018 Full ramp-up in production expected by mid 2019 Future Thermal Development 2P Reserves can support 20,000 bbl/d for 20+ years Company Lands Thermal Heavy Oil Pay Current Thermal Production Area (12,000 bbl/d) 11

Blackrod SAGD The Basics Located in the Athabasca oil sands 100% owned and operated Grand Rapids reservoir Current Status Successful pilot operated since 2012 Pilot well has produced >675,000 bbl Potential Received regulatory and environmental development approval 80,000+ bbl/d (several phases) SAGD Pilot Long life asset with 30+ year project life Capital cost estimate of $35,000 per flowing bbl Good economics at WTI oil prices of $US 55+/bbl, with normalized differentials 1 mile Working Interest Lands Application Area Thermal Pay (>10 m) Phase 1 Wells Phase 2 and 3 Wells Central Processing Facility Shale Channels 12

Financial Strength 2.50 2.00 1.50 1.00 0.50 0.00 $100mm undrawn on credit facility Debt Capital $75mm Senior Notes $20mm Drawn on Credit Facility Debt/Funds Flow Ratio history (1) 2014 2015 2016 2017 2018e 2019e $120mm Syndicated Credit Facility ATB, National, Canadian Western Reserve based lending Floating rate, currently 3.5% $100 mm undrawn at Dec 31, 2017 $75mm Senior Notes Held by Prudential Capital 8% coupon Matures in 2020 Debt peaks at $130 140 mm during Onion Lake Phase 2 thermal expansion By the end of 2019 debt is expected to be <1.0x funds flow (1) Estimates are based on WTI oil price of US$62/bbl, differential of US$21.50/bbl, FX of 0.80 in 2018 and WTI oil price of US$60/bbl, differential of US$18/bbl, FX of 0.80 in 2019 13

2018 Guidance 2018 Estimates 2017 2018e Production (boe/d) Average 10,199 11-12,000 Exit 10,500 14,000 Capital expenditures ($mm) 170 80-85 Adjusted funds flow ($mm) 59 60-65 Y/E debt ($mm) 93 130-140 Price assumptions WTI ($US/bbl) $50.95 $62.00 Heavy Differential ($US/bbl) $12.03 $21.50 FX 0.77 0.80 In 2019, when production from the Onion Lake expansion is fully ramped-up, funds flow are projected to be $125+ mm ($US60/bbl WTI; $US18/bbl WCS differential) Funds Flow Sensitivities ($mm) 80 60 40 20 0 $45 WTI $50 WTI $62 WTI $70 WTI Capital spending in 2018 reduced as Onion Lake phase 2 reaches completion Every $US1/bbl change in WTI changes funds flow by $3 mm Production will ramp-up through the year as we bring on phase 2 at Onion Lake 2018 exit production expected to be 40% higher than 2017 14

Oil Prices $70.00 $60.00 $50.00 $40.00 $30.00 $20.00 $10.00 $- $- $(5.00) $(10.00) $(15.00) $(20.00) $(25.00) $(30.00) Jan-15 WTI Oil Price (US$/bbl) Mar-15 May-15 Jul-15 Sep-15 Nov-15 Jan-16 Mar-16 May-16 Jul-16 Sep-16 Nov-16 Jan-17 Mar-17 May-17 Jul-17 Sep-17 Nov-17 Jan-18 Heavy Oil Differential (US$/bbl) Jan-15 Mar-15 May-15 Jul-15 Sep-15 Nov-15 Jan-16 Mar-16 May-16 Jul-16 Sep-16 Nov-16 Jan-17 Mar-17 May-17 Jul-17 Sep-17 Nov-17 Jan-18 Rebound in WTI oil prices over the last four months Supply/demand rebalancing in the market Heavy oil differentials have widened during the same period Reaching existing pipeline capacity Keystone pipeline leak and Enbridge line repairs Rail congestion Improvement in differentials anticipated Short term improved rail logistics Mid term one of 3 pipelines built Longer term all 3 pipelines built 15

Improved Market Access Three major North American pipelines are approved and scheduled to start-up in less than 3 years which will help to alleviate the current Canadian heavy oil discount Kinder Morgan Trans Mountain Expansion +590,000 bbl/d Enbridge Line 3 Expansion +380,000 bbl/d TransCanada Keystone XL +800,000 bbl/d West Coast Mid Continent Gulf Coast More Takeaway = Diversified Markets = Better Heavy Oil Pricing 16

Hedging Program We use oil hedging to mitigate downside risk to support our capital program and debt repayment Oil price is hedged out for the forward 18 months We have also hedged approximately 25% of our natural gas consumption costs for the next 2 years 7000 Summary of Oil Hedging Program bbl/d 6000 5000 4000 3000 WCS Swaps C$49.55 WCS Swaps C$49.55 WTI Collars F-US$40-45 C-US$51-60 WTI Collars F-US$40-45 C-US$51-63 2000 1000 WTI Collars F-US$40-45 C-US$50-58 WTI Collars F-US$40-45 C-US$50-58 WTI Collars F-US$40-44 C-US$57-60 WTI Collars F-US$40-44 C-US$59-60 0 % Hedged Q1/18 Q2/18 Q3/18 Q4/18 Q1/19 Q1/19 52% 51% 51% 49% 20% 20% (1) WCS refers to Western Canadian Select, a heavy oil reference price (2) % hedged is based on estimated production, net of royalties (3) In addition to these swaps and collars, the Company has sold calls for 1,000 bbl/d in 2018 at US$70/bbl and has entered into a WTI/WCS differential hedge for Q1 2018 at C$16.25/bbl 17

Appendices

Company Overview Corporate Symbol: Exchanges: PXX, PXXS TSX, OMX Ownership Shares Outstanding (mm) (1) Basic 337 Fully Diluted 364 Current Share Price ($/share) 1.08 Market Capitalization ($mm) 375 Management Ownership 9%/11% Exchanges TSX, OMX 49% 18% 12% Burgundy Asset Management Franklin Templeton Lundin Family Financial (2) Working Capital ($mm) -24 Debt Outstanding ($mm) 95 Total Credit Facilities ($mm) 195 9% 12% Management Other Operational Current Production (boe/day) 10,000 2P Reserves (mmboe) (3) 162 2C Risked Resource (mmboe) (3) 640 (1) As at March 21, 2018 (2) As at December 31, 2017 (3) Source: Sproule reserve and risked contingent resource (best estimate) reports effective December 31, 2017 (see Cautionary Statement on Contingent Resources in the Disclaimer section of the presentation) 19

2017 Oil and Gas Reserves - Summary 24% increase in 1P reserves year over year Reserves added at Onion Lake 48% increase in 1P reserve value 2P reserve value is equivalent to $6/sh Yearend 2017 (1) Volume BT PV10% (mmboe) ($mm) Proved Reserves 94 1,085 Probable Reserves 68 932 2P Reserves 162 2,017 2P Reserves Breakdown (1) Other, 2% Mooney, 10% Onion Primary, 3% Other, 2% Mooney, 11% Onion Lake Primary, 3% Onion Thermal, 85% Onion Lake Thermal, 84% Volume BT PV10% (1) Source: Sproule reserve report effective December 31, 2017 20

Contingent Resources - Summary Risked Volume BT PV10% Area Class (mmboe) (1) ($mm) (1) Blackrod Phase 1 Dev Pending 169 555 Blackrod Phases 2 & 3 Dev On Hold 436 n/a (2) Onion Lake Dev Pending 24 158 Mooney Dev On Hold 11 n/a (2) Contingent Resource Volume Breakdown (1) Mooney, 2% Blackrod Ph 2 & 3, 68% Onion Lake, 4% Blackrod ph 1, 26% 640 mmboe risked contingent resource (best estimate) volumes for our 3 core properties (1) Increased 28% from yearend 2016 The value of the first 20,000 bbl/d phase of Blackrod is equivalent to $1.65/sh (1) Future phases at Blackrod could add an additional 60,000 bbl/d (1) Source: Sproule risked contingent resource (best estimate) reports effective December 31, 2017 (see Cautionary Statement on Contingent Resources in the Disclaimer section of the presentation) (2) The values of the contingent resources associated with of phases 2 & 3 of the Blackrod SAGD project and Mooney to be determined as we get closer to development 21

2018 Guidance 2018 Capital Spending ($ mm) Other, $13 Blackrod, $2 Our 2018 focus will be on completing the phase 2 expansion at Onion Lake as well as sustaining capital (one additional well pad) Onion Lake Primary, $6 Onion Lake Thermal (Sustaining),$24 Onion Lake Thermal (Ph 2), $39 We will resume our conventional development program in our other areas Minimal activity in these areas in last 3 years due to low prices and our focus on Onion Lake thermal projects Our capex program will be funded from cash flow and existing bank lines 22

Onion Lake Thermal Design Capacity 7,000 6,000 Onion Lake Phase 1 Thermal Production Ramp-Up (bbl/d) 5,000 4,000 3,000 2,000 1,000 Initial steam injection Facility turnarounds & inspections 0 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Jan-16 Feb-16 Mar-16 Apr-16 May-16 Jun-16 Jul-16 Aug-16 Sep-16 Oct-16 Nov-16 Dec-16 Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17 Jan-18 23

Blackrod s Regional Reach Illustrated below are 48 well logs encompassing 16 Blackrod sections Homogeneous + Continuous = Predictable + Scalable 24