February 2018

SPARTAN ENERGY CORP.Corporate Presentation

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Stock symbol TSX : SPE

Market cap / Enterprise value(1)(2) $1.1B / $1.3B

Average daily volume(3) 1.9mm shares

Shares outstanding 176.6mm (b) / 187.8mm (d)

Insider ownership 5.5% (b) / 10.1% (d)

2018 forecast production (avg/exit) 23,400 / 25,000 boe/d

Oil & liquids weighting 91%

Reserves (gross)(4) 73.0 MMboe (1P) 113.5 MMboe (P+P)

Net debt(5) $199 million

Credit facility $350 million

Tax pools(6) $1.8B

Corporate Snapshot

(1) Market Capitalization and enterprise value based on SPE share price as at January 31, 2018.(2) Enterprise value represents fully diluted market capitalization plus net debt (excluding finance lease obligations), less the proceeds of dilutive securities.(3) Average daily trading volume from 01/01/17 to 12/31/17; composite data from all Canadian exchanges(4) Reserve numbers were derived from an independent reserves report prepared by Sproule Associates Ltd. (“Sproule”) effective December 31, 2016 based

on Sproule December 31, 2016 forecast pricing.(5) Estimated net debt as of December 31, 2017, excluding finance lease obligations of $26.8 million. Estimated net debt is unaudited and subject to change.(6) As at September 30, 2017.

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• Key elements of success:

1) Asset Quality

Mississippian light oil in SE Sask consistently ranks as one of the top plays in NA(1)

Low risk, repeatable development and exploitation drilling with attractive capital efficiencies

2) Growth and Decline Management

Focused on long term value creation – target attractive but sustainable growth level

Decline management contributes to growth – leads to increased free cash flow

Supplement organic growth through waterflood projects and accretive acquisitions

3) Balance sheet management

Prudent management of balance sheet offsets commodity price risk

(1) Scotiabank: “The Playbook: Ranking North America’s Oil & Gas Plays – 8th Edition” October, 2017.

Formula for Success

⨍x =

1) 10%+ annual production per share growth within cash flow

+2) Proactively manage declines

+3) Prudent balance sheet management

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SE Saskatchewan Asset BaseScale and Repeatability

G. QueensdaleFrob-Alida

G.CantalFrob-Alida

G. WordsworthFrob-Alida

AlamedaFrac Midale

Midale/Frob OH

PintoFrac Midale

G. Workman-WinmoreFrobisher

ElcottMidale Frac/OH

OungreRatcliffe / Torquay

WeyburnCO2 Flood

MidaleCO2 Flood

LougheedMidale

Estevan

Weyburn

BromheadTorquay

399,000 net acres (55% Crown)

2.5 billion barrels OOIP on SPE lands (net)

Ownership & control of producing infrastructure

Significant 3D seismic coverage (1.1mm acres)

Top tier netbacks

Low decline production (~26%)

Strong capital efficiencies

>1,500 net drilling locations

22 waterflood projects, largely unbooked

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SE Sask Mississippian GeologyConventional Open Hole and Frac’d Midale

• Shallow marine environment• Interbedded limestones, dolomites and evaporites• Structural and stratigraphic traps

• Conventional Mississippian: ranks among the top plays in North America

• Sub 1 year payouts at WTI US$50 oil• Excellent geological properties (permeability and

porosity)• Wells are drilled open hole (typically ½ mile – 1

mile Hz)

• Unconventional Midale: tight oil resource play• low permeability, large OOIP• Wells are equipped with a cemented liner and

completed with a 35 stage frac, 1 mile Hz

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CORE AREA FORMATION WI LOCATIONS2018

BUDGET

(%) (Gross) (Net)

Conventional Mississippian (Open Hole) 81% > 1,500 > 1,200 93

Frobisher/Alida 79% >1,000 >775 56

Midale 91% >275 >225 8

Tilston 76% >125 >100 0

Ratcliffe 87% >100 >100 29

Unconventional tight oil (Frac) 87% > 1,000 > 875 44

Midale 92% >325 >275 30

Bakken & Torquay 81% >125 >100 0

Viking 87% >550 >500 14

TOTAL SASK 84% >2,500 >2,100 137

Drilling Locations

• Location count as at YE 2017. Numbers may not add due to rounding.

• All conventional and Frac Midale locations are risked, have been vetted by geology and 3D seismic.

• Minimal down-spaced locations (75m inter-well spacing) included and does not include contingent locations.

• Only 30% of locations are currently booked.

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Type Well Economics (1)(2)(3)(4)

AREA COST IP90 EUR NPV BT10% IRR (BT) PAYOUT

($M) (Boe/d) (Mboe) ($mm) (%) (years)

SE Saskatchewan – open hole $800 92 65 $1.1 – $1.6 113 – 192 1.0 – 0.7

SE Sask. – Ratcliffe (open hole) $1,100 76 80 $2.2 135 1.0

SE Saskatchewan – Frac Midale $1,600 176 191 $1.5 - $2.1 55 – 82 1.7 – 1.3

SE Sask – Torquay (frac) $2,450 161 130 $2.7 80 1.3

West Central Sask – Viking (Type 6) $900 64 50 $0.6- $1.0 38 – 61 2.3 – 1.6

Notes:

1) Unrisked.

2) Based on Sproule December 31, 2017 escalated price forecast (WTI US$55.00/$65.00/$70.00 – 2018/19/20) assuming Jan. 1, 2018 start date.

3) Assumes WTI/Cdn Light differential of 8% and SPE quality differential of CAD$4.00.

4) Range of values denotes whether well drilled on freehold or Crown lands. Where only a single value is presented, it is assumed that the well is drilled on Crown land.

G. QueensdaleFrob-Alida

G.CantalFrob-Alida

G. WordsworthFrob-Alida

G. Workman-WinmoreFrobisher

OungreRatcliffe

WeyburnCO2 Flood

MidaleCO2 Flood

LougheedMidale

Estevan

Weyburn

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Conventional Mississippian Open Hole Plays

Ranks among the top plays in North America

Sub 1 yr. payouts at WTI US$55 oil

>1,500 (>1,200 net) locations

Largely unbooked – only 32% of locations booked

2018 drilling program = 93 locations

Frobisher/Alida ~ 65% of undrilled locations

Frobisher, Midale, Tilston and Ratcliffe

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SE Saskatchewan Open Hole Well PerformanceOpen Hole Mississippian (Frobisher/Alida/Kisby + Tilston + Midale) Light Oil

• >95% success rate

• Historical drilling program has consistently outperformed SPE internal type curve – 197 wells on production

AlamedaFrac Midale

Midale/Frob OH

PintoFrac Midale

ElcottMidale Frac/OH

OungreTorquay

Estevan

Weyburn

BromheadTorquay

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SE Saskatchewan Tight Oil Frac PlaysFrac Midale/Bakken/Torquay

Exposure to large unbooked reserve upside

Low risk repeatable drilling inventory in the frac Midale

Significant position in emerging Torquay resource play

>450 (>375 net) locations

Only 33% booked

2018 drilling program = 30 locations

Frac Midale PlayAlameda, Pinto, Elcott

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• Production: > 4,000 boe/d

• Unconventional tight oil resource play

• Large oil in place with low recovery factor

• Ownership/control of infrastructure to support future development

• Significant waterflood upside at Pinto and Alameda – 3.5 section pilot at Alameda delivering early results with additional 5.5 section project approved

• >325 (>275 net) drilling locations

• 40% of locations unbooked

• 30 net locations budgeted in 2018

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SE Saskatchewan Frac Midale Well PerformanceFrac Midale Light Oil

• 100% success rate

• Unconventional tight oil resource play with large oil in place with low recovery factor

• 55 Frac Midale wells drilled to date outperforming the SPE type well on average

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Spartan Torquay Land PositionOungre and Bromhead Areas – Southeast Saskatchewan

• Over 125 gross (100 net) drilling locations (prospective lands unrisked at 4 wells per section)

• All locations currently unbooked

• Industry activity adjacent to SPE acreage continues to de-risk the play

WESTALL PNG

EASTTo Base Ratcliffe

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Locations >550 gross (500 net)

Viking inventory includes infill & pooled locations and unriskedlocations on Plato lands at 13 wells/section

23 new sections at Plato – 100% SPE WI

2018 drilling program = 14 locations

West Central Saskatchewan Tight OilFrac Viking

1st well IP90 = 60bbld/d

AlamedaFrac Midale

Pinto UnitsFrac Midale

Winmore-Workman-ElmoreFrobisher

Oungre UnitRatcliffe

LougheedMidale

WeyburnCO2 Flood

MidaleCO2 Flood

Glen EwenMidale

Skinner Lk.Ratcliffe

ElcottMidale

Wier HillFrobisher

WilmarFrobisher

WordsworthAlida

ArcolaAlida

StorthoaksAlida

BryantMidale

SteelmanFrobisher

Oungre Non-UnitRatcliffe

Weyburn UnitsMidale

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Waterflood / EOR ProjectsSignificant Unbooked Upside

• 22 projects on Company lands that have waterflood or EOR upside

• Affects over 50% of existing base production

• Significant unbooked reserve potential

• Includes optimization/expansion of existing waterflood and EORprojects

• Initiation of waterflood projects on both conventional and non-conventional assets

• Benefits:• Long term value creation (F&D < $5.00/bbl)• Significantly improved recovery factors• Strong recycle ratio (>6x)• Decline mitigation

Oungre Unit

Freda Lake Unit

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Oungre Unit - Ratcliffe Waterflood ProjectOungre Voluntary Unit No. 1

• SPE WI = 100%• OOIP = 90 Mmbbls• Current Production = ~500 bbl/d (5% decline)• Base RF = 21%• Ultimate RF w/ waterflood = 38%• Freda Lake analogy for optimal development

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Oungre Unit - Waterflood Development Plan

• OOIP = 90 mmbbl (Oungre unit only) – 100% SPE working interest

• $87mm development capital – Phase I commenced in Q4 2017 with peak oil in 2 – 3 years

• Scalable to include non-Unit lands

Phase 1 Commencing Q4 2017

1818

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1000

2000

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4000

5000

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7000

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3/25/1960 12/2/1973 8/11/1987 4/19/2001 12/27/2014 9/4/2028 5/14/2042 1/21/2056

Oil

Rat

e b

bl/

day

Date

Oil Rate

Oungre Unit Development Plan• 5 re-entry into existing Hz to add leg in B zone• 25 dual leg Hz wells into A & B• 26 single leg Hz into the Oungre C • 53 injector conversions• 10 new vertical injector drills• Pipeline and battery upgrades

• Total capital = $87mm• Incremental oil recovered = 18 mmbbl

• F&D = $4.80• Peak production = 6,500 boe/d• NPV10BT = > $300mm

Oungre Unit - Waterflood Model

1) Production rates, F&D costs and NPV based on internal Spartan model which includes assumptions relating to timing of capital expenditures, production response and commodity prices. Actual results may differ materially.

Weyburn & Midale Units

CO2 EOR Units Overview

Weyburn/Midale

Weyburn UnitCenovus WI 62.11%

SPE WI 6.95%

Midale UnitCardinal WI 68.84%

SPE WI 15.54%

• Largest geological greenhouse gas sequestration project in the world. Over 2.5 million tonnesof CO2 are injected and stored each year

• 6.95% WI in Weyburn and 15.54% WI in Midale

• 3% - 4% decline across both units supports stable, predictable long term cash flow

• Current production net to SPE of ~ 2,300 boe/d

• Nearly two billion barrels of original-oil-in-place (“OOIP”) across Weyburn and Midale Units

• Ultimate recovery factor in Weyburn estimated to be up to 50%

• Significant torque to rising oil prices

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Significant Unbooked Upside

Lougheed Ownership• Average WI: 85.80%

Oil in Place• Large OOIP = ~ 242 gross / 210 net MMbbls• RF to Date = 13%

Geology• Reservoir characteristics are analogous to Weyburn unit (similar

porosity, permeability and thickness)• Weyburn Unit ultimate RF projected to reach 50% - 60%

Upside• Significantly under-developed compared to the Weyburn and

Midale Units.

• Potential for substantial increase in reserves and recoverable oil at Lougheed with successful implementation of infill drilling, waterflood expansion/optimization and future CO2 flood

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Capital Spending

DCE&T (74%)

Maintenance (8%)

Weyburn/Midale CO2 (5%)

EOR (8%) (discretionary)

Land (2%) (discretionary)

Capitalized G&A (2%)

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2018 Budget

Capital Allocation

Open-hole (35%)

Frac Midale (33%)

Ratcliffe (22%)

Viking (10%)

• Spartan’s 2018 budget is structured to:

deliver sustainable growth (6% growth in avg.production per share and 11% exit to exit growth)

manage corporate declines (est. at 26% for 2018)

maintain the company’s strong financial position(forecasted to exit 2018 with net debt to 2018 cash flowof 0.6x)

• Total development capital spending to achieve 2018 productiongrowth is $183 million, (69% of forecast 2018 cash flow @ WTIUS$60.00).

• Excess cash flow forecasted at $84 million, a portion of which($22 million) has been earmarked for investment in projectsthat add incremental growth and long term value for SPEshareholders (Oungre waterflood)

• Focus is on capital projects that generate the highest rate ofreturn:

64 open hole wells targeting the Frobisher and Midaleformations (35% of DC&E budget)

30 frac Midale wells (33% of DC&E budget)

29 Ratcliffe wells, including 12 Hz wells in the OungreUnit waterflood project (22% of DC&E budget)

• Remaining excess cash flow after discretionary expenditures tofund strategic acquisitions and/or share buy backs

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2018 Budget GuidanceProduction

Average daily production (boe/d) 23,400Exit production (boe/d) 25,000% oil and liquids 92%

1) See Disclaimers - “Non-IFRS Measures”

2) 2018 exit net debt is exclusive of finance lease obligations and assumes all discretionary capital is spent in 2018.

FinancialCash flow ($MM)(1) $267Per share – basic(1) $1.51Development capital ($MM) $183Excess cash flow ($MM)(1) $84Discretionary capital ($MM) $222018 exit net debt to 2018 cash flow(1) 0.6x

PricingCrude oil – WTI (US$/bbl) $60.00Exchange rate ($Cdn/$US) 1.25Natural gas – AECO ($/mcf) $2.00Cromer Oil ($Cdn/bbl) $69.50

Netbacks ($/boe)Oil and gas sales $59.53Royalties $9.52Production expense $16.65Operating netback(1) $33.36G&A (cash portion) $1.09Interest $1.05Corporate netback $31.22

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2018 Cash Flow Sensitivity

1) Forecast only. Actual results will differ due to a number of factors. See Disclaimers – “Forward Looking Statements”.

2) Corporate Netback, Cash Flow, Excess Cash Flow, Development Capital and Net Debt are non-IFRS measures. See “Non-IFRS Measures”.

3) Development capital includes drilling, facilities, maintenance, HS&E and capitalized G&A. Discretionary capital Includes EOR projects, land and seismic.

4) Excess cash flow calculated as cash flow less development capital spending.

5) 2018 exit net debt is exclusive of finance lease obligations and assumes all discretionary capital is spent in 2018. Based on SPE share price of $7.04.

Oil (US$WTI) $50.00 $55.00 $60.00 $65.00 $70.00

FX (C$/US$) $0.78 $0.79 $0.80 $0.81 $0.82

Differential to Cromer (C$/bbl) $5.00 $5.00 $5.00 $5.00 $5.00

Corporate Netback ($/boe)(2) $22.81 $27.06 $31.22 $35.24 $39.18

Average Production (boe/d) 23,400 23,400 23,400 23,400 23,400

Exit Production (boe/d) 25,000 25,000 25,000 25,000 25,000

Cash Flow(MM)(2) $195 $231 $267 $301 $335

Development Capital (MM)(2)(3) $183 $183 $183 $183 $183

Excess Cash Flow ($MM)(4) $12 $48 $84 $118 $152

Discretionary Capital ($MM)(2)(3) $22 $22 $22 $22 $22

Payout Ratio excl. Discretionary Capital (%) 94% 79% 69% 61% 55%

Payout Ratio incl. Discretionary Capital (%) 105% 89% 77% 68% 61%

Net Debt to Cash Flow(5) 1.1x 0.8x 0.6x 0.4x 0.2x

Excess cash flow yield(5) 1% 4% 7% 10% 12%

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RICHARD (RICK) MCHARDY, B.Comm., LLB., - President & CEO20+ years experience in M&A /securities matters and oil and gasPresident, CEO Spartan Oil Corp.; President, CEO Spartan Exploration Ltd.; President, Titan Exploration Ltd.;Partner, McCarthy Tetrault LLP.

ALBERT STARK, M. Eng., P.Eng – Senior Vice President, Operations20+ years (Titan, Devon, Northstar, Amoco)Vice President Operations, Spartan Oil Corp.; Vice President Operations, Spartan Exploration Ltd.; VP Engineering & COO, Titan Exploration Ltd.; Manager of Prod. & Asset Optimization, Devon Canada

FOTIS KALANTZIS, P.Geoph., Ph.D. – Senior Vice President, Exploration20+ years (Innova, Petro-Canada, Aramco, Suncor, Wascana, Home Oil)Vice President Exploration, Spartan Oil Corp.; Vice President, Exploration, Spartan Exploration Ltd.; Exploration Manager and Geophysicist, Innova Exploration Ltd.,

ED WONG, P. Eng., - Senior Vice President, Engineering20+ years (Samson, BP Canada/Amoco)Vice President Engineering, Spartan Oil Corp.; Vice President, Engineering, Spartan Exploration Ltd.; Hoadley Business Unit Manager, Samson Canada Resources Ltd.

RANDY BERG, P. Land. – Vice President, Land20+ years of Oil & Gas experienceVice President, Business Development and Land, Renegade Petroleum; Land Manager/Business Unit Manager, PetroBakkenEnergy Ltd.; Senior Staff Landman, NAL; Vice President Land, Alberta Clipper Energy Inc.

ADAM MACDONALD, B.Comm, C.A. – Chief Financial Officer6+ years (Renegade Petroleum, Spartan)Audit and Assurance Group, PriceWaterhouse Coopers (2007 – 2011)

Management

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BOARD OF DIRECTORS

Michael StarkChairmanIndependent Businessman

Don ArchibaldIndependent Businessman

Reg GreensladeIndependent Businessman

Richard (Rick) McHardy

Grant GreensladePresident, Greenslade Consulting Group

BANKER

National Bank

EVALUATION ENGINEERS

Sproule Associates Limited

REGISTRAR & TRANSFER AGENT

Alliance Trust Company

LEGAL COUNSEL

McCarthy Tétrault LLP

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AltaCorp Capital Inc. (Thomas Matthews)

BMO Capital Markets (Ray Kwan)

Canaccord Capital Corp. (Anthony Petrucci)

Clarus Securities Inc. (Daniel Choi)

CIBC World Markets Inc. (Dave Popowich)

Cormark Securities Inc. (Garett Ursu)

Desjardins Capital Markets (Kristopher Zack)

Eight Capital Corp. (Adam Gill)

GMP FirstEnergy (Stacey McDonald)

Macquarie Capital Markets Canada Ltd. (Brian Kristjansen)

National Bank Financial (Dan Payne)

Raymond James Ltd. (Jeremy McCrea)

Paradigm Capital Inc. (Ken Lin)

Peters & Co. (Jeff Martin / Cindy Mah)

Scotia Capital Inc. (Cameron Bean)

TD Securities Inc. (Juan Jarrah)

Analyst Coverage

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Head OfficeSuite 3200, 500 Centre Street SECalgary, Alberta T2G 1A6Telephone: 403-355-8920Facsimile: 403-355-2779E-mail: info@spartanenergy.cawww.spartanenergy.ca

For Further InformationPlease Contact:

Mr. Richard (Rick) McHardyPresident & CEOEmail: rmchardy@spartanenergy.ca

Mr. Tim SweeneyManager, Business DevelopmentEmail: tsweeney@spartanenergy.ca

DisclaimersForward Looking Statements. Certain information included in this presentation constitutes forward-looking information under applicable securities legislation. Forward-looking information typically contains statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", "project" or similar wordssuggesting future outcomes or statements regarding an outlook. Forward-looking information in this press release may include, but is not limited to, statements about ourcorporate strategy, timing and level of 2018 capital expenditures, future acquisition opportunities, future production levels, 2018 netbacks and cash flows, 2018 exit netdebt, exit production and net debt to funds flow ratio, unutilized liquidity, drilling location, Spartan’s ability to reduce or accelerate spending, economics and payouts ofour wells, future waterflood, land and seismic investments and future commodity prices and exchange rates. Statements relating to "reserves" are also deemed to beforward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantitiespredicted or estimated and that the reserves can be profitably produced in the future.

The forward-looking statements contained in this presentation are based on certain key expectations and assumptions made by Spartan, including expectations andassumptions concerning the success of future drilling, development and completion activities, the performance of existing wells, the performance of new wells, theavailability and performance of facilities and pipelines, the geological characteristics of Spartan's properties, the successful application of drilling, completion and seismictechnology, prevailing weather and break-up conditions and access to our drilling locations, commodity prices, royalty regimes and exchange rates, the application ofregulatory and licensing requirements, the availability of capital, labour and services, our ability to complete planned capital expenditures within budgeted cost estimates,the ability to market oil and gas successfully, our ability to integrate assets and employees acquired through acquisitions, the creditworthiness of industry partners and ourability to acquire additional assets.

Although Spartan believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placedon the forward-looking statements because Spartan can give no assurance that they will prove to be correct. Since forward-looking statements address future events andconditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number offactors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration andproduction; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety andenvironmental risks), incorrect assessment of the value of acquisitions, failure to realize the benefits of acquisitions, constraint in the availability of services, commodityprice and exchange rate fluctuations, changes in legislation (including but not limited to tax laws, royalty regimes and environmental legislation), adverse weather orbreak-up conditions and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures.Production forecasts are directly impacted by commodity prices and the actual timing of our capital expenditures. Actual results may vary materially from forecasts due tochanges in interest rates, oil differentials, exchange rates and the timing of expenditures and production additions. These and other risks are set out in more detail inSpartan's Annual Information Form for the year ended December 31, 2016.

The forward-looking information contained in this press release is made as of the date hereof and Spartan undertakes no obligation to update publicly or revise anyforward-looking information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws. The forward lookinginformation contained in this press release is expressly qualified by this cautionary statement.

This presentation contains future-oriented financial information and financial outlook information (collectively, "FOFI") about Spartan's prospective results of operations,cash flow, free cash flow, operating and cash netbacks, net debt, operating costs and components thereof, all of which are subject to the same assumptions, risk factors,limitations and qualifications as set forth in the above paragraphs and the assumption outlined in the Non-IFRS measures section below. FOFI contained in thispresentation was made as of the date of this presentation and was provided for the purpose of providing further information about Spartan's anticipated future businessoperations. Spartan disclaims any intention or obligation to update or revise any FOFI contained in this presentation, whether as a result of new information, future eventsor otherwise, unless required pursuant to applicable law. Readers are cautioned that the FOFI contained in this presentation should not be used for purposes other thanfor which it is disclosed herein.

Disclaimers (continued)Oil and Gas Advisories

BOE Disclosure. The term barrels of oil equivalent (“BOE”) may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet of natural gasto barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at thewellhead. All BOE conversions in the report are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.

Reserves Disclosure. All reserve references in this press release are to gross reserves as at the effective date of the applicable evaluation. Gross reserves are the Company’stotal working interest reserves before the deduction of any royalties and including any royalty interests of the Company. The recovery and reserve estimates of Spartan’scrude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crudeoil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.

Type Curves. Certain type curves disclosure presented herein represent estimates of the production decline and ultimate volumes expected to be recovered from wells overthe life of the well. The type curves represent what management thinks an average well will achieve. Individual wells may be higher or lower but over a larger number ofwells, management expects the average to come out to the type curve. Over time type curves can and will change based on achieving more production history on older wellsor more recent completion information on newer wells.

Drilling Locations. This presentation discloses drilling inventory in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locationsand probable locations are derived from the applicable engineering evaluation and account for drilling locations that have associated proved and/or probable reserves, asapplicable. Unbooked locations are internal estimates based on our prospective acreage and an assumption as to the number of wells that can be drilled per section based onindustry practice and internal review. Unbooked locations do not have attributed reserves or resources. Of the >2,500 gross drilling locations identified by Spartan, 464 areproved locations, 322 are probable locations and >1,700 are unbooked locations. Unbooked locations have been identified by management as an estimation of our multi-yeardrilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that we will drill all unbookeddrilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which weactually 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 relativeclose proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where management has less information about thecharacteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wellswill result in additional oil and gas reserves, resources or production.

Non-IFRS Measures. This press release provides certain financial measures that do not have a standardized meaning prescribed by IFRS. These non-IFRS financial measuresmay not be comparable to similar measures presented by other issuers. Funds flow from operations, excess cash flow, operating netback, development capital, net debt andnet debt exclusive of finance lease obligations are not recognized measures under IFRS. Management believes that in addition to net income (loss), funds flow fromoperations, operating netback, development capital, net debt and net debt exclusive of finance lease obligations are useful supplemental measures that demonstrate theCompany’s ability to generate the cash necessary to repay debt or fund future capital investment. Investors are cautioned, however, that these measures should not beconstrued as an alternative to net income (loss) determined in accordance with IFRS as an indication of Spartan’s performance. Spartan’s method of calculating thesemeasures may differ from other companies and accordingly, they may not be comparable to measures used by other companies. Cash flow from operating activities iscalculated by adjusting net income (loss) for other income, unrealized gains or losses, accretion expense, stock-based compensation, exploration and evaluation expenses,deferred income taxes, impairment and depletion and depreciation. Funds flow from operations is calculated based on cash flows from operating activities before changes innon-cash working capital, transaction costs and decommissioning obligation expenditures incurred. Operating netback is calculated based on oil and gas revenue less royaltiesand operating and transportation expenses. Free cash flow is calculated as funds flow from operations less development capital. Development capital includes all drilling,completions, equipping and tie-in costs as well as facilities, maintenance, environmental and capitalized G&A expenditures but excludes land, seismic and waterfloodexpenditures and acquisitions. Net debt is calculated as bank debt plus trade and other liabilities plus finance lease obligations less current assets. Net debt has beenpresented exclusive of finance lease obligations, as Spartan believes that such measure is useful to evaluate Spartan’s financial liquidity. Estimated net debt excludes theoutstanding principal amount of finance lease obligations. Estimated net debt to cash flow as at December 31, 2018 includes discretionary land, seismic and waterfloodspending in 2018 but excludes .

Greater QueensdaleOpen Hole Frobisher/Alida

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• Production ~3,000 boe/d

• OOIP = 400 MMbbls across 10 pools @ current 29% RF

• Average WI = 85%

• Location Upside: >240 (180 net) drilling locations 25% downspaced locations

• Technical Work: 900+ wells with log picks, net pay,

and phi assignments Refined geological edges Large 3D seismic coverage

• Drilling Results: Historically delivers >10% above SPE type curve

• Recovery Factor: Analogue pools with down spacing have demonstrated 33% to 44% RF to date. Queensdale is currently at 29% RF; potential for 20-to-40 mmbbls of additional recoverable oil based on incremental 5% - 10% RF.

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SE Saskatchewan Queensdale Frobisher Well PerformanceOpen Hole Frobisher/Alida Light Oil

• Historical drilling program has consistently outperformed SPE internal type curve – 73 wells on production (not including strat tests or mechanical failures)

• Large inventory of high quality, low risk, repeatable development and exploitation drilling opportunities in an oil field with 400 mbbls OOIP

Gainsborough W

Winmore

Elmore

Workman

SherwoodSouris Flats

Carnduff

Greater Workman-WinmoreOpen Hole Frobisher

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• Production ~2,500 boe/d

• Multi zone potential in the Frobisher

• > 300 (240 net) locations

• Wells significantly above SPE type curve (Avg. IP 30 ~ 200 bbl/d)

• Waterflood upside

Workman Unit 1 & 3 optimization

Winmore: initiated with 2 Hz injectors; future expansion

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SE Saskatchewan Winmore Frobisher Well PerformanceOpen Hole Frobisher Light Oil

• 94% success rate

• Historical drilling program has consistently outperformed SPE internal type curve – 46 wells on production

• Recent acquisition has expanded location inventory in Winmore

• Large inventory of high quality, low risk, repeatable development and exploitation drilling opportunities in 2 pools, and a current RF of <6%