Highwood's Clearwater Position

Highwood Oil Company Ltd.

Corporate Presentation

February 2020 Recent Developments

Highwood Oil Company Ltd. (“Highwood” or the “Company”) is an emerging intermediate oil producer with operations in Alberta and Saskatchewan listed on the TSX-V under the trading symbol “HOCL” ▪ Agreement to divest majority of non-core Red Earth assets to an arms length private company Red Earth Disposition ▪ Disposed current production of approximately 950 bbl/d of oil ▪ Consideration of $8.0 million in cash, a 5% GORR, and 10% ownership in the acquiror ▪ Disposition materially improves operational focus and liability profile ▪ 90% of pro-forma production is concentrated in the Clearwater play ▪ Transaction reduces corporate decommissioning obligations by 87% or ~$32 million (pro- forma $4.5 million at September 30/19) ▪ Focus of capital spending plan on growing production & reserves in the Clearwater property 2020 Guidance ▪ $10.0 – 15.0 million capital spending program ▪ Majority of activity targets low-risk infill drilling with immediate cash flow visibility ▪ Compliment infill drilling with select step-out wells to further delineate Clearwater position

▪ Post disposition, Highwood emerges as the only public, pure play Clearwater producer Corporate Outlook ▪ 196 (99 net) sections in the heart of the Clearwater play ▪ Targeting net Clearwater production of 1,300 bbl/d by year-end 2020 (1,550 bbl/d of corporate production, weighted 100% oil) ▪ Pipeline provides a diversified cash flow base with a mix of E&P and midstream revenue ▪ $5.0 million of annual cash flow ownership in the Wabasca River Pipeline ▪ Highwood is well positioned to pursue organic growth and opportunistic acquisitions in the Clearwater play

Highwood will continue to focus its efforts throughout 2020 on delineating its Clearwater lands in a capital-efficient manner, while mainly pursuing infill and pad drilling development opportunities offsetting positive initial production results 2 Highwood Growth Execution History

▪ Founded in 2012 as a private company under the name Predator Oil

▪ Recently went public through a reverse take-over of a capital pool company in Q1 2019

▪ The Company has executed 6 materially accretive acquisitions and 3 highly profitable dispositions since inception in 2012

▪ Team has provided positive returns to shareholders since inception in Highwood and other midstream and upstream entities

TIMELINE – BALANCING ORGANIC LAND CAPTURE AND M&A

Equal Canada Mosaic West Wabasca River Pipeline Red Earth

Transaction – 800 boe/d Central – 2,350 boe/d 100% WI Acquisition Divestiture – 950 bbl/d

Acquired Equal Energy’s Mannville gas acquired Flows 5,000+ bbl/d onto Plains Non-core asset divestiture of

2012 2018 2020 Canadian assets in 2012; 2017 through receivership Rainbow Pipeline (75% 3rd party substantially all Red Earth sold majority of the process; disposed of the volumes) with capacity up to production and liability. Pro- acquired asset base asset in 2017 20,000 bbl/d. Assets include 6 forma LMR of 4.8 pipeline connected batteries

Red Earth Clearwater Land Saskatchewan

Asset – 1,250 boe/d Acquisition and Development Transaction – 230 bbl/d Active

Capital deployed to mitigate decline – Acquired 196 gross (99 net) Very accretive acquisition of ~230 2019 2014 and increase production; cleaned up Clearwater sections; sold 4% GORR bbl/d of light sweet crude oil

and abandoned well bores to improve 2017 in September 2018, covering ~90% produced from 7 gross (5.5 net) wells LMR of Clearwater lands. Drilled 14 in the Tilston formation wells to year end 2019

3 Corporate Overview

Market Summary – HOCL.V Core Properties

1 2020 Guidance WABASCA 2020 Exit Production bbl/d 1,550 PIPELINE Capital Expenditures MM $10 - 15 Operating Costs $/boe $8.50 - 9.50 Upstream Netback $/boe $27.00 - 29.00 CLEARWATER 2020 Field Net Op Income MM $21

Core Assets CLEARWATER ▪ Largely unbooked, economic, high growth & value potential ▪ Current Gross Production of 1,500 bbl/d (100% liquids; 50% WI) ▪ 196 gross (99 net) sections

WABASCA RIVER PIPELINE SASKATCHEWAN ▪ Stable and diversified cash flow generated from 3rd party volumes ▪ ~$5.0 million annual cash flow AB SK Complementary Non-Core Assets ▪ Saskatchewan - Tilston light oil play with ~150 bbl/d of production ▪ Red Earth (100 bbl/d and 50 bbl/d of royalty production), Peace River Arch (50+ net sections Montney/Doig), Whitecourt/Carson (100+ net sections Beaverhill Lake/Duvernay) 1) 2020 Guidance is pro-forma the Red Earth Disposition highlighted on Slide 2, anticipated to close on or around April 2020. Estimated operating results based WTI US$53.00/bbl, WCS differential US$17/bbl, Edm differential 4 US$6.00/bbl and FX 1.33 CAD/USD Clearwater Oil Resource Fairway Landscape

CLEARWATER DEVELOPMENT AREAS Clearwater activity has strongly increased since the first half of 2017 ▪ Highwood, Spur, Deltastream, CVE and CNRL have all been active T90 ▪ Well configurations, spacing, and lengths all evolving Golden Evi Rangeland Midstream building a new 85km pipeline (COD H2/20) T88 ▪ Providing the first pipe connection egress to the play

Play is being developed with ESG atop of mind T86 ▪ Sweet produced gas is reused to power surface operations Cadotte ▪ Decreased land use with up to 10 wells off of one surface Godin T84 ▪ No stimulation – no water used for fracturing T82 IRR & PAYOUT BY NORTH AMERICAN PLAY 250% 5.0 T80 Canadian Plays U.S. Plays Payout Pelican Doucette T78 200% 4.0

T76 150% 3.0 Payout Marten Hills Nipisi T74

IRR IRR (%) 100% 2.0 T72

50% 1.0 Nixon T70 Canal 0% 0.0 T68

T66 Craigend

Newbrook T64 Jarvie Edwand CLEARWATER PRODUCTION GROWTH T62 40 400 Pre-2015 2015 2016 2017 2018 2019 Total Wells T60 30 300

Production in the Clearwater R17 R15 R13 R11 R9 R7 R5 R3 R1W5 R24 R22 R20 R18 R16 R14 R12W4 WellCount(#)

20 play now exceeds 25,000 bbl/d 200 Legend: Baytex Crestwynd Harvest Rolling Hills Plains Pipeline 10 100 Production (Mboe/d) Production Cardinal/Summerland Deltastream Mancal Spur Planned Rangeland Pipeline Cenovus ISH Obsidian Turnstone Operator Batteries 0 0 Jan.16 Jul.16 Jan.17 Jul.17 Jan.18 Jul.18 Jan.19 Jul.19 CNRL Highwood Perpetual 5 Sources: Corporate Estimates, geoSCOUT, PETRINEX , XI Technologies Highwood’s Clearwater Position

The Clearwater oil play is one of the most significant discoveries made over the last 10 years Highwood Nipisi Drilled fourteen 4 to 8 leg wells ▪ 14-22o API oil, 100-4,500 Cp viscosity 12 wells on production Area players have been active in Clearwater delineation efforts ▪ North: Highwood, Spur, Deltastream, CNRL, Cenovus North ▪ South: Highwood, Spur, Crestwynd ▪ >185 wells are on-stream and >50 upcoming licenses(1) Highwood Craigend Highwood Jarvie Drilled one 4 leg well Clearwater play economics are top-decile to industry Drilled two 4 leg in Feb 2020 wells in 2018 ▪ Unstimulated, multi-pad & multi-lateral hztl (up to 8 legs) ▪ Year-round access, close proximity to major highways ▪ Shallow and repeatable resource at TVDs of 600-850m South ▪ Quick cycle times (four-leg well: ~14 drilling days) Highwood’s expansive land position provides investors the greatest exposure to the Clearwater within the public markets ▪ 196 gross (99 net), minimal land expiries ▪ North / South: ~47% / ~53% split HOCL GROSS PRODUCTION GROWTH ▪1 North - Primary project: Lower (75%) & Upper (25%) 2,000 14 sands Production Well Count ▪ 53 multi-laterals drilled (incl. 12 by HOCL) 12 1,600

▪ Continued drilling into Q1 2020 with 20+ additional wells 10 surveyed / ready to license by HOCL (#)Count Well 1,200 2▪ South – Secondary Exploration: Lower (50%) Sand 8

▪ 33 multi-laterals drilled (incl. three by HOCL); 2 Jarvie, 1 6 Production(bopd) 800 Craigend 4 ▪ HOCL: 10+ wells surveyed / ready to license; capital program 400 for 2 to 4 wells in 2020 2

0 0 Dec.18 Jan.19 Feb.19 Mar.19 Apr.19 May.19 Jun.19 Jul.19 Aug.19 Sep.19 Oct.19 Nov.19 Dec.19 1) As per geoSCOUT data, as at December 2018 6 2) Defined as “peak” 30-day rate post clean-up North Clearwater Acreage: Nipisi Assets

Spur Nipisi Project Area Activity Highwood Q1 Capital Program 9 Lower Clearwater Wells Drilled 2 Lower Clearwater 13 Upper Clearwater Wells ▪ 53 wells drilled to date in Main Highways Wells from Mid Jan to Mid Feb 4 to 6 legged wells Peak Rates 40-310 bopd Nipisi/Mistue • 13 Upper Clearwater • 40 Lower Clearwater ▪ Two operators to date have been Spur and Highwood (50% WI) Highwood 12-18 Well 3m lower than Clearwater ▪ Oil viscosities range from 100 to Highwood 9-18 Well producers to north more than 5000 cP (30C) with 20m structurally lower Extended play 1 km south majority around 100-1000 cP Extended play 5km west Performing as expected Performing as expected Nipisi ▪ Peak rates range from 40 to 310 bopd with best rates and highest quality oil found in the Lower Clearwater Highwood ▪ Highwood has drilled and completed 14 Lower Clearwater wells to date (50% working Highwood Nipisi interest). 14 Lower Clearwater wells drilled and 12 wells on ▪ Highwood has a slated capital production (Feb 2020) program of 12-16 multilateral Spur Mitsu Peak Rates 45-260 bopd 19 Lower Clearwater Wells wells (6 legs) in the area subject 3 to 8 legged wells 4 to 6 legged wells to performance and oil pricing Peak Rates 40-180 bblsd Mitsue

HOCL Lands (50% WI)

7 South Clearwater Acreage: Jarvie Newbrook

Main Highways

10 Crestwynd HZ Wells Perryvale 4 to 6 legs per well Ish HZ Stage Fracked Wells Peak Rates 80-210 bopd Jiles Bolloque Jarvie

15 Spur & 2 Highwood HZ Wells Meanook 3-6 legs per well 1 new Rolling Hills new well Peak Rates 70-210 bopd Production cleaning up 2 Crestwynd HZ Wells 6 leg wells 1 Rolling Hills/Crewtwynd new well Peak Rates 50-90 bopd Production cleaning up Newbrook

Area Activity HOCL Lands (50% WI) ▪ 32 multilateral wells drilled with 3 to 6 legs per well ▪ Main operators are Spur, Crestwynd, Highwood and Rolling Hills ▪ Viscosity ranges from 400 to 4500 cP (at 30C) across area ▪ Peak rates range from 50 to 210 bopd with type well at 140 bblsd ▪ Last 5 wells drilled by Crestwynd & Spur ranged with public production info from 140-210 bopd peak rates ▪ Water cuts typically range from 15-25% of total fluid and appear to get better with time Highwood ▪ Highwood has (2 to 4) 6-legged horizontal wells scheduled in capital budgeted in Meanook, Jarvie and Jiles 8 2020 Capital Budget – Results Driven Focus on Nipisi

Highwood’s approved Capital development includes 5-10 Clearwater wells focused at Nipisi, but the company will remain flexible and ultimately be driven by results and commodity prices ▪ Continue to focus on Nipisi with a balanced approach to cash flow generation and low risk delineation wells ▪ Pad drills convert resource into operating funds flow at > 3x recycle ratio

SINGLE WELL ECONOMICS CLEARWATER TYPE CURVES Other Development/Tier Nipisi 200 Areas Nipisi Typecurve Formation Zone Clearwater 180 Other Area Typecurve Capex ($M) $1,485 $1,380 160 IP30(1) (boe/d) 200 150

EUR(2) (Mboe) 175 110 140 IRR (%) 117% 58% 120 Payout (Yr) 1.1 1.6

NPV10 ($M) $2,532 $1,228 100 bbl/d Rec. Ratio / Cycle Time(3) (x) / (days) 3.5x / 40 2.4x / 40 80 PI Ratio (x) 2.59 1.4

CLEARWATER PAD SENSITIVITIES (3) 60 WTI US$/bbl $40 $50 $60 $70 40 ROR (%) 17 86 191 300

NPV10 ($M) $250 $1,800 $3,400 $5,000 20 Payout (Yr) 3.4 1.3 0.8 0.6 Rec. Ratio (x) 1.4x 2.8x 4.3x 5.7x 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Month Economics based on WTI US$53.00/bbl, WCS differential US$17/bbl, Edm differential US$6.00/bbl and FX 1.33 CAD/USD 1) IP30 is defined as peak 30-day rate 2) The type curve and 2P EUR has been developed by a qualified reserves evaluator (QRE) and in accordance with the Canadian Oil and Gas Evaluation (COGE) Handbook. The QRE is a company employee, a professional member of APEGA and has over 15 years of relevant industry and evaluation experience. 9 3) Recycle Ratio is calculated as operating netback to half-cycle finding & development costs; cycle time is defined as the number of days elapsed from initial drilling to first production Infrastructure

PROVIDING A DIVERSIFIED FUNDS FLOW BASE

Infrastructure ownership provides diversification ▪ Highwood holds a 100% WI in the Wabasca R11 R7 R3 River Pipeline ▪ ~$5.0 million of operating funds flow per year ▪ All of Highwood’s light sweet oil flows on the T95 system central to the Red Earth assets ▪ Open access with public tolls (CNRL, Mancal and Surge are users of the system) ▪ Evi terminal soon to be capable of handling trucked-in volumes

Highwood operates 210 km of transmission T91 pipeline (incl. 12 transmission lines) ▪ Connects the Senex, Trout, Kidney, Sawn Lake and Evi areas of Alberta ▪ Capacity of 20,000 boe/d ▪ Capacity > 4x current flow ~5,000 boe/d

T87

Highwood Wabasca System Highwood North Senex System Third Party System Receipt Points Delivery Points

10 Summary Highlights (1)

▪ Low Risk Base Assets Highly sustainable free funds flow generating base provides maximum corporate flexibility ▪ Diversified revenues from high quality upstream and midstream assets

▪ Target 2020E production of ~1,550 boe/d weighted 100% oil Stable Production ▪ Low corporate decline of ~20%, strong average capital efficiencies of ~$11k per boe/d (2)

▪ High netback of $28/bbl(3) with minimal sustaining capex drives significant free funds flow Strong Funds Flow ▪ Free funds flow provides flexibility to fund growth, repay debt or pursue accretive acquisitions

Manageable Asset ▪ Strong LMR of 4.8 trending upward with continued Clearwater capital activities Obligations ▪ Statement of Financial Position Decommissioning Liabilities of ~$4.5MM (Sept 30/19 Red Earth Disposition pro-forma) FUTURE OPPORTUNITIES

Organic Growth ▪ Significant growth potential in the Clearwater area (>300 net locations)(4)

▪ Leverage Highwood’s expertise and proven track record of value creation through M&A Mergers & Acquisitions ▪ Execute on counter-cyclical acquisitions to build size, scale and drive improved efficiencies

FOCUSED ON EXECUTION THROUGH OPERATIONAL EXCELLENCE AND PRUDENT FINANCIAL MANAGEMENT FOR SELF- FUNDED AND SUSTAINABLE FUTURE GROWTH

1) Summary Highlights are Pro-forma the Red Earth Disposition highlighted on Slide 2, anticipated to close on or around April 2020 2) Capital efficiency based on achieving pad type curves (based on first-year average production) for Clearwater (~$11,000/boe/d) 3) Estimated operating netback based WTI US$53/bbl, WCS differential US$17/bbl, Edm differential $6/bbl , Fx 1.33 11 4) Management’s internally identified estimate of locations Management, Board of Directors and Partners

Management Position Background

 Mr. Macdonald has more than 20 years of experience in both Canada and the U.S.. Previously, Mr. Macdonald President & CEO, Greg Macdonald, P.Eng. was the VP, Engineering of Tidewater Midstream & Infrastructure Ltd., a public oil & gas midstream company; Director prior thereto, Mr. Macdonald worked in various engineering roles at both private and public oil and gas companies

 Mr. Glans is a Chartered Accountant and CFA Charterholder with over 10 years of financial and management Graydon Glans, CA, CFA CFO experience with public and private companies; previously, Mr. Glans was the Operations Controller, PRD Canada for Secure Energy Services and Manager, Financial Reporting at Predator Midstream

 Mr. McDonald is a Professional Geologist with over 25 years of oil and gas experience in Canada and the US; Mr. Kelly McDonald, P.Geol. VP, Exploration McDonald has been an officer in a number of oil and gas companies over the last 10 years and has been intricately involved in exploration and development of both conventional and unconventional assets across North America

Board Member Position Background

 President & CEO, Fireweed Energy, former VP Drilling & Completions Tangle Creek Energy, VP Operations Steve Holyoake, P.Eng. Chairman SkyWest Energy Corp and former Manager, Drilling & Completions at Berens Energy Ltd.

 Mr. Macdonald has more than 20 years of experience in both Canada and the U.S. Previously, Mr. Macdonald President & CEO, was the VP, Engineering of Tidewater Midstream & Infrastructure Ltd., a public oil & gas midstream company; Greg Macdonald, P.Eng. Director prior thereto, Mr. Macdonald worked in various engineering roles at both private and public oil and gas companies

Arif Shivji, CA, CFA, MBA Director  CFO Highwood (2012-2014), Predator Midstream CFO, Manager Transaction Services PwC Advisory

 Trevor Wong-Chor is a partner in DLA Piper LLP’s Calgary office and practices primarily in the areas of Trevor Wong-Chor Director securities, mergers & acquisitions, corporate, and oil and gas law

Partner

Reserve Evaluator  GLJ Petroleum Consultants Ltd.

Bank  National Bank of Canada

Auditor  RSM Alberta LLP 12 Advisory Regarding Forward Looking Statements

Forward Warnings In the interest of providing readers with information regarding Highwood Oil Company Ltd. (“Highwood”), including management's assessment of Highwood's future plans and operations, this presentation contains certain forward‐looking statements and other information (collectively “forward‐looking information”) about Highwood’s current expectations, estimates and projections and may include, but are not limited to: the anticipated closing date of the Acquisition; the actual amount of debt assumed upon closing of the Acquisition; the number of Highwood shares issued upon closing of the Acquisition; the sources of existing production and future development drilling locations and opportunities; the annual decline rate of the Assets; the number and classification of future development drilling locations and opportunities; the pricing received for production, and resulting operating and after-tax cash flow netbacks for the Assets; the estimate of annualized 2020 fund flows from operations; the anticipated acquisition metrics; the expectation that fiscal and regulatory policies in Alberta remain supportive of continued investment; exploration and development capital expenditure expectations for 2020; and development plans and strategic objectives. Forward‐looking information in this presentation is identified by words such as “anticipate”, “believe”, “expect”, “plan”, “intend”, “estimate”, “forecast”, “target”, “project”, “could”, “focus”, “vision”, “goal”, “proposed”, “scheduled”, “outlook”, “potential”, “may”, “looking forward to”, or similar expressions and includes suggestions of future outcomes, and include, without limitations, statements with respect to Highwood's future focus, plans, operations and strategies, the benefits associated with Highwoods's asset base, well economics, drilling and development plans, drilling costs, capital and operating costs, netbacks, 2020 production, capital expenditures and funds flow guidance, targeted debt to funds flow ratio, decline rates, transportation costs, recovery factors, drilling inventory, rates of return, payout, and infrastructure development plans. Statements relating to reserves and resources are also forward‐looking statements, as they involve the implied assessment, based on estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated and can be profitably produced in the future. The forward‐looking statements contained in this presentation speak only as of the date of this presentation and are expressly qualified by this cautionary statement.

These forward‐looking statements are based on assumptions and are subject to numerous risks and uncertainties, certain of which are beyond Highwood’s control, the impact of general economic conditions, industry conditions, volatility of commodity prices, currency exchange rate fluctuations, imprecision of reserve and resource estimates, environmental risks, industry capacity, geological, technical, drilling and processing problems and other difficulties in producing reserves, disruptions in the transportation networks on which Highwood is reliant, changes in income tax laws, liabilities inherent in oil and natural gas operations, competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel, risks associated with operations, our reliance on key personnel, changes in royalty rates and incentive programs relating to the oil and gas industry, changes in environmental and other regulations, incorrect assessments of the value of acquisitions and the benefits to be derived therefrom, stock market volatility and ability to access sufficient capital. As a result, Highwood’s actual results, performance or achievement could differ materially from those expressed, or implied by, these forward‐looking statements and, accordingly, no assurance can be given that any events anticipated by the forward‐looking statements will transpire or occur. In addition, the reader, is cautioned that historical results are not necessarily indicative of future performance. Highwood does not intend, and does not assume any obligation, to update or revise these forward‐looking statements, whether as a result of new information, future events or otherwise, except as required by applicable securities laws.

Although Highwood believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Highwood can give no assurance that such expectations will prove to be correct. Forward-looking statements or information are 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 Highwood and described in the forward looking statements or information. These risks and uncertainties include but are not limited to: the ability of management to execute its business plan or realize anticipated synergies or cost savings from the Acquisition; the risks of not obtaining court, shareholder, regulatory and other approvals for the Acquisition; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil and natural gas and market demand; risks and uncertainties involving geology of oil and natural gas deposits; risks inherent in Highwood's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life; the uncertainty of estimates and projections relating to production, costs and expenses; potential delays or changes in plans with respect to proposed acquisitions (including the Acquisition), exploration or development projects or capital expenditures; Highwood's ability to enter into or renew leases; fluctuations in oil and natural gas prices, foreign currency exchange rates and interest rates; health, safety and environmental risks; uncertainties as to the availability and cost of financing; the ability of Highwood to add production and reserves through development and exploration activities; general economic and business conditions; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Highwood; and other risks and uncertainties described elsewhere in this document or in Highwood's other filings with Canadian securities regulatory authorities. 13 Other Advisory Regarding Forward Looking Statements

The forward-looking statements or information contained in this document are made as of the date hereof and Highwood undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws.

Certain information set out herein may be considered as “financial outlook” within the meaning of applicable securities laws. The purpose of this financial outlook is to provide readers with disclosure regarding Highwood’s reasonable expectations as to the anticipated results of its proposed business activities for the periods indicated. Readers are cautioned that the financial outlook may not be appropriate for other purposes.

Any references in this document to test rates, flow rates, initial and/or final raw test or production rates, early production, and/or "flush“ production rates are useful in confirming the presence of hydrocarbons, however, such rates are not necessarily indicative of long‐term performance or of ultimate recovery. Such rates may also include recovered "load" fluids used in well completion stimulation. Readers are cautioned not to place reliance on such rates in calculating the aggregate production for Highwood. Such rates may be estimated based on other third party estimates or limited data available at this time and are not determinative of the rates at which such wells will continue production and decline thereafter.

Statements relating to reserves are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated, and can be profitably produced in the future. Such forward-looking statements or information are based on a number of assumptions all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: satisfaction of all conditions to the proposed Acquisition and receipt of all necessary approvals; availability of credit facilities for the completion of the Acquisition; the non- operating partner’s intention to maintain its status quo interest in respect of its rights of tag along or first refusal contained in the PROP partnership agreement; the ability of Highwood to obtain equipment, services and supplies in a timely manner to carry out planned development activities; the ability of Highwood to market oil and natural gas successfully to current and new customers; the timely receipt of required regulatory approvals; currency, exchange and interest rates; future oil and natural gas prices; and Management's expectations relating to the timing and results of development activities.

14 Other Advisory Regarding Forward Looking Statements

Estimates of the net present value of the future net revenue from the reserves included in this presentation do not represent the fair market value of such reserves. In this presentation NPV10 represents the net present value of future net reserve discounted at 10%. The estimates of reserves and future net revenue from individual properties or wells may not reflect the same confidence level as estimates of reserves and future net revenue for all properties and wells, due to the effects of aggregation.

This presentation contains type curves and well economics. The type curve information presented is based on Highwood's historical production. Such type curves and well economics are useful in understanding management's assumptions of well performance in making investment decisions in relation to development drilling and for determining the success of the performance of development wells; however, such type curves and well economics are not necessarily determinative of the production rates and performance of existing and future wells.

This presentation contains a number of metrics commonly used in the oil and natural gas industry, such as "payout" and internal rate of return ("IRR"). These terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this presentation, should not be relied upon for investment or other purposes. In this presentation "payout" is calculated by taking the time, in years, to recover the total costs to drill, complete and equip a well from operating netbacks and "IRR" is calculated as the return on investment, based on production from a well, using management estimated type curves and EURs. "EUR" means estimated ultimate recovery and is calculated as those quantities of petroleum which are estimated, on a given date, to be potentially recoverable from an accumulation, plus those quantities already produced therefrom. Oil and Gas Measures Barrel of oil equivalent (“boe”) amounts may be misleading, particularly if used in isolation. A boe conversion ratio has been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel. This conversion ratio of six thousand cubic feet of natural gas to one barrel 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 The flowing definitions do not have a standardized meaning prescribed by Canadian generally accepted accounting principles ("GAAP") and therefore may not be comparable with the calculation of similar measures by other companies. “Free funds flow” is calculates as funds flow less capital expenditures. “Free funds flow yield” is calculated as free funds flow / market capitalization. “Funds flow” is calculated as operating funds flow less general and administrative expenses and interest expenses. “Funds flow netback” is calculated as revenues net of royalties, less transportation and processing charges, operating expenses, general and administrative expenses and interest expenses and then divided by BOE of Mcf sold. “Net debt” is calculated as total debt less current assets plus current liabilities (excluding any amounts included in total debt), and includes transaction costs and the completed debt and equity financings. Total debt is calculated as long-term debt, long-term debt due within one year and short-term debt. “Operating free funds flow” is calculated as revenues net of royalties, less transportation and processing charges and operating expenses less capital expenditures. “Operating free funds flow yield” is calculated as operating free funds flow divided by transaction value. “Operating funds flow” is calculated as revenues net of royalties, less transportation and processing charges and operating expenses. “Operating netback” is calculated as revenues net of royalties, less transportation and processing charges and operating expenses and then divided by BOE or Mcf sold. “Sustainability ratio” is calculated as Capital Expenditures / Funds Flow

15 Other Advisory Regarding Forward Looking Statements

Future Locations This release discloses drilling locations in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations are derived from the GLJ Petroleum Consultants Report effective December 31, 2018 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates prepared by a qualified reserves evaluator based on 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 drilling locations do not have attributed reserves. Of the 300 net drilling locations identified herein, 0.5 are proved locations, 3 are probable locations, and the balance are unbooked locations. Unbooked locations have been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that Highwood will drill all unbooked drilling locations and, if drilled, there is no certainty that such locations will result in additional oil and gas reserves or production. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, 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, some of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics 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 or production.