SPARTAN ENERGY CORP. Corporate Presentation November 2017 Corporate Snapshot

Stock symbol TSX : SPE Market cap / Enterprise value(1)(2) $1.2B / $1.5B Average daily volume(3) 2.0mm shares Shares outstanding 175.5mm (b) / 186.7mm (d) Insider ownership 5.5% (b) / 10.2% (d)

2017 forecast production 22,000 boe/d Oil & liquids weighting 91% Reserves (gross)(4) 69.2 MMboe (1P) 109.1 MMboe (P+P) Net debt(5) $205.1 million Credit facility $350 million Tax pools(6) $1.8B

(1) Market Capitalization and enterprise value based on SPE share price as at September 29, 2017. (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 07/01/17 to 10/31/17; 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) As at September 30, 2017, excluding finance lease obligations of $27.9 million. (6) As at December 31, 2016. 2  376,000 net acres (59% Crown) SE Asset Base  2.5 billion barrels OOIP on SPE lands (net) Scale and Repeatability  Ownership & control of producing infrastructure  Significant 3D seismic coverage (1.1mm acres)  Top tier netbacks  Low decline production (~25%)  Strong capital efficiencies  >1,600 net drilling locations  22 waterflood projects, largely unbooked

Weyburn

G. Wordsworth Frob-Alida Lougheed G. Queensdale Frob-Alida Midale G.Cantal CO Flood CO2 Flood 2 Frob-Alida

Alameda Bromhead Frac Midale Torquay Midale/Frob OH Oungre Ratcliffe / Torquay Pinto Elcott G. Workman-Winmore Frac Midale Midale Frac/OH Frobisher

3 Formula for Success

1) 8% - 10% annual organic production per share growth within cash flow + 2) Proactively manage declines ⨍x = + 3) Prudent balance sheet management + 4) Reinvest free cash flow to supplement growth

• 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. 4 Per Share Growth

5 Drilling Locations

2017 CORE AREA FORMATION WI LOCATIONS BUDGET (%) (Gross) (Net)

Conventional Mississippian (Open Hole) 81% > 1,500 > 1,200 70 Frobisher/Alida 79% >975 >750 56 Midale 91% >225 >200 0 Tilston 76% >125 >100 6 Ratcliffe 87% >100 >100 8

Unconventional tight oil (Frac) 87% > 1,000 > 875 38 Midale 92% >250 >225 22 Bakken & Torquay 81% >200 >150 2 Viking 87% >550 >475 14

TOTAL SASK 84% >2,500 >2,100 108 • Location count as at Q2 2017. Numbers may not add due to rounding. • All conventional locations are risked, have been vetted by geology and seismic. • Unconventional Bakken/Torquay locations are unrisked and at 4 wells per section. • Viking inventory includes pooled locations and unrisked locations on newly acquired lands at 13 wells/section. • Minimal down-spaced locations (75m inter-well spacing) included and does not include contingent locations. • Only 30% of locations are currently booked.

6 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 $725 82 75 $1.2 – $1.6 139 – 240 0.9 – 0.6

SE Sask. – Ratcliffe (open hole) $1,100 76 80 $1.9 117 1.1

SE Saskatchewan – Frac Midale $1,500 176 191 $1.8 - $2.4 68 – 97 1.5 – 1.1

SE Sask – Torquay (frac) $2,450 161 130 $2.3 67 1.5

West central Sask – Viking (Type 5) $700 45 40 $0.4 - $0.7 32 – 50 2.7 – 1.9

Notes: 1) Unrisked. 2) Based on GLJ Q3 2017 escalated price forecast (WTI US$52.00/$57.00/$62.00 – 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.

7 Conventional Mississippian Open Hole Plays Frobisher, Midale, Tilston and Ratcliffe

 Ranks among the top plays in North America  Sub 1 yr. payouts at WTI US$50 oil  >1,500 (>1,200 net) locations  Largely unbooked – only 32% of locations booked  2017 drilling program = 70 locations  Frobisher/Alida ~ 65% of undrilled locations

Weyburn

G. Wordsworth Frob-Alida Lougheed Midale G. Queensdale Frob-Alida Midale Weyburn G.Cantal CO Flood CO2 Flood 2 Frob-Alida

Estevan Oungre Ratcliffe G. Workman-Winmore Frobisher

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

• Historical drilling program has consistently outperformed SPE internal type curve – 183 Wells on production (not including exploration wells, strat tests or mechanical failures)

• 183 Mississippian open hole wells drilled: 16 Tilston, 162 Frobisher , 5 Midale

9 Greater Queensdale Open Hole Frobisher/Alida • Production ~3,000 boe/d

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

• Average WI = 85%

• Location Upside: . >250 drilling locations . 25% downspaced locations

• 60% of locations unbooked

• Technical Work: . 900+ wells with log picks, net pay, and phi assignments . Refined geological edges . Large 3D seismic coverage

• Drilling Results: Historically delivers 10% - 20% above SPE unrisked 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.

10 SE Saskatchewan Queensdale Frobisher Well Performance Open Hole Frobisher/Alida Light Oil

• Historical drilling program has consistently outperformed SPE internal type curve – 69 wells on production (not included strat tests or mechanical failures but included 2 infills @ 75 m spacing drilled in Q1 2017)

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

11 Greater Workman-Winmore Open Hole Frobisher

• Production ~2,500 boe/d

• Multi zone potential in the Frobisher

• > 200 (190 net) locations

• Only 23% of locations are booked

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

• Waterflood upside

. Workman Unit 1 & 3 optimization . Winmore: initiated with 2 Hz injectors; future expansion

12 SE Saskatchewan Winmore Frobisher Well Performance Open Hole Frobisher Light Oil

• Historical drilling program has consistently outperformed SPE internal type curve – 42 wells on production (not included strat tests or mechanical failures)

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

13 Oungre Open Hole Ratcliffe Light Oil

• Conventional Ratcliffe play – additional upside in Upper Ratcliffe and potential unconventional frac play • 100% Crown acreage - wells qualify for deep well royalty credit (16,000 m3) • Significant waterflood upside • >100 net drilling locations • H2 2017 program = 8 net wells

14 SE Saskatchewan Ratcliffe Well Performance Open Hole Ratcliffe Light Oil

• 2017 drilling program has outperformed SPE internal type curve – 9 wells on production

• Large inventory of high quality, low risk, repeatable development and exploitation drilling opportunities with significant waterflood upside

15 SE Saskatchewan Tight Oil Frac Plays Frac 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

 2017 drilling program = 24 locations

Weyburn

Alameda Bromhead Frac Midale Torquay Midale/Frob OH Estevan Oungre Torquay Pinto Elcott Frac Midale Midale Frac/OH

16 Frac Midale Play Alameda, Pinto, Elcott

• 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

• >250 (>225 net) drilling locations

• 40% of locations unbooked

• 22 net locations drilled in 2017

17 SE Saskatchewan Frac Midale Well Performance Frac Midale Light Oil

• Unconventional tight oil resource play with large oil in place with low recovery factor • 53 Frac Midale wells drilled to date outperforming the SPE type well on average

18 Spartan Torquay Land Position Oungre and Bromhead Areas – Southeast Saskatchewan

WEST ALL PNG

EAST To Base Ratcliffe

• Over 175 gross (125 net) prospective drilling locations (unrisked at 4 wells per section) - all currently unbooked • Industry activity adjacent to SPE acreage continues to de-risk the play • Spartan plans to drill first two operated Torquay wells in 2nd half of 2017

19 West Central Saskatchewan Tight Oil Frac Viking

1st well IP90 = 60bbld/d

 Locations >550 gross (475 net)  Only 20% booked  Viking inventory includes infill & pooled locations and unrisked locations on newly acquired lands at 13 wells/section  23 new sections at Plato – 100% SPE WI  2017 drilling program = 14 locations

20 • 22 projects on Company lands that have waterflood or EOR upside Waterflood / EOR Projects • Affects over 50% of existing base production Significant Unbooked Upside • Significant unbooked reserve potential • Includes optimization/expansion of existing waterflood and EOR projects • Initiation of waterflood projects on both conventional and non- conventional assets • Benefits: • Long term value creation (F&D < $4.00/bbl) • Significantly improved recovery factors • Strong recycle ratio (>8x) • Decline mitigation

Arcola Alida

Weyburn Units Midale Wordsworth Alida

Wier Hill Wilmar Frobisher Frobisher Lougheed Midale Midale Weyburn CO Flood 2 Steelman CO2 Flood Alida Skinner Lk. Bryant Frobisher Ratcliffe Midale Alameda Frac Midale Oungre Non-Unit Midale Ratcliffe Oungre Unit Ratcliffe Winmore-Workman-Elmore Pinto Units Frobisher Frac Midale Elcott Midale

21 Waterflood Illustrative Example Oungre 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

Freda Lake Unit Oungre Unit

22 Oungre Waterflood Development Plan Phase 1 Commencing Q4 2017

• OOIP = 90 mmbbl (Oungre unit only) – 100% SPE working interest • $45mm development capital – Phase I commencing in Q4 2017 with peak oil in 2 – 3 years • Scalable to include non-Unit lands

23 Conversion of existing verticals into injectors & addition of horizontal infill wells • Incremental recoverable reserves = 15 mmbbl • F&D = $3.00/bbl

21% RF 38% RF

24 CO2 EOR Units Overview Weyburn & Midale Units • Largest geological greenhouse gas sequestration project in the world. Over 2.5 million tonnes Weyburn/Midale of 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 50% - 60%

• Significant torque to rising oil prices

Weyburn Unit Midale Unit Cenovus WI 62.11% Cardinal WI 68.84% SPE WI 6.95% SPE WI 15.54%

25 Lougheed Ownership • Average WI: 85.80% Significant Unbooked Upside 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

26 2017 – Top Tier Growth Within Cash Flow

2016(1) 2017 Forecast(2) % Change Average Production (boe/d) 11,748 22,000 87% • Per share (MM) 396 458 16%

Cash Flow ($MM)(3) $76.8 $180.0 135% • Per share $0.71 $1.03 45% Development Capital ($MM)(3) $61.8 $140.0 127% • Total net wells drilled 53.7 112.0 109%

Excess Cash Flow(3)(4) $14.9 $40.0 168% • Per share $0.14 $0.23 64%

Basic Payout Ratio 80% 78% (3)% YE Net Debt to Cash Flow(5) 0.8x 1.1x 38%

1) 2016 per share amounts reflect 3:1 share consolidation that occurred on June 20, 2017. 2) 2017 forecast based on oil price for 2H 2017 of US$50 WTI and Cdn/US FX of $0.80. Actual results will differ due to a number of factors. See Disclaimers – “Forward Looking Statements”. 3) Cash Flow, Excess Cash Flow, Development Capital and Net Debt are non-IFRS measures. See “Non-IFRS Measures”. 4) Excess cash flow calculated as funds flow less development capital (drilling, facilities, maintenance, HS&E and G&A). 5) 2016 YE net debt has been adjusted to remove the additional net debt incurred on December 8, 2016 to finance a portion of the ARC Acquisition. 2016 cash flow has also been adjusted to remove 24 days of cash flow generated from the ARC assets in 2016. Ratio of year-end net debt to 2017 cash flow based on assumptions set forth above. 2017 YE Net Debt assumes Q4 2017 excess cash flow used to pay down debt. 27 2H 2017 Cash Flow Sensitivity

Second Half 2017 Average Prices

Oil (US$WTI) $40.00 $45.00 $50.00 $55.00 $60.00

FX (C$/US$) $0.75 $0.77 $0.80 $0.81 $0.82 AECO (C$/Mcf) $2.50 $2.50 $2.50 $2.50 $2.50 Impact on 2017 Annual Results

Corporate Netback ($/boe)(2) $18.57 $20.53 $22.40 $24.20 $26.22

Average Production (boe/d) 22,000 22,000 22,000 22,000 22,000

Cash Flow(MM)(2) $149 $165 $180 $194 $211

Development Capital (MM)(2) $140 $140 $140 $140 $140

Excess Cash Flow(MM)(2)(3) $9 $25 $40 $54 $71

Annual 2017 Sensitivities: +/- US$1.00 WTI : $8.1mm +/- $0.10 AECO: $0.3mm +/- $0.01 FX: $5.3mm

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) Excess cash flow calculated as cash flow less development capital (drilling, facilities, maintenance, HS&E and capitalized G&A).

28 Management

RICHARD (RICK) MCHARDY, B.Comm., LLB., - President & CEO 18+ years experience in M&A /securities matters and oil and gas President, 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, Operations 18+ 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

FOTIS KALANTZIS, P.Geoph., Ph.D. – Senior Vice President, Exploration 20+ 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, Engineering 20+ 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, Land 20+ years of Oil & Gas experience Vice President, Business Development and Land, Renegade Petroleum; Land Manager/Business Unit Manager, PetroBakken Energy Ltd.; Senior Staff Landman, NAL; Vice President Land, Alberta Clipper Energy Inc.

ADAM MACDONALD, B.Comm, C.A. – Chief Financial Officer 4+ years (Renegade Petroleum, Spartan) Audit and Assurance Group, PriceWaterhouse Coopers (2007 – 2011)

29 BOARD OF DIRECTORS BANKER Michael Stark National Bank Chairman Independent Businessman

Don Archibald EVALUATION ENGINEERS Independent Businessman Sproule Associates Limited Reg Greenslade Independent Businessman REGISTRAR & TRANSFER AGENT Richard (Rick) McHardy Alliance Trust Company Grant Greenslade President, Greenslade Consulting Group LEGAL COUNSEL McCarthy Tétrault LLP

30 Analyst Coverage

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. (Amir Arif)

Desjardins Capital Markets (Kristopher Zack)

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)

31 Head Office Suite 500, 850 – 2nd Street SW Calgary, Alberta T2P 0R8 Telephone: 403-355-8920 Facsimile: 403-355-2779 E-mail: [email protected] www.spartanenergy.ca

For Further Information Please Contact:

Mr. Richard (Rick) McHardy President & CEO Email: [email protected]

Mr. Tim Sweeney Manager, Business Development Email: [email protected]

32 Disclaimers

Forward 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 words suggesting future outcomes or statements regarding an outlook. Forward-looking information in this press release may include, but is not limited to, statements about our corporate strategy, timing and level of 2017 capital expenditures, future acquisition opportunities, future production levels, 2017 netbacks and cash flows, 2017 exit net debt, exit production and net debt to funds flow ratio, unutilized liquidity, drilling location, Spartan’s ability to reduce or accelerate spending, economics and payouts of our wells, future waterflood, land and seismic investments and future commodity prices and exchange rates. Statements relating to "reserves" are also 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 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 and assumptions concerning the success of future drilling, development and completion activities, the performance of existing wells, the performance of new wells, the availability and performance of facilities and pipelines, the geological characteristics of Spartan's properties, the successful application of drilling, completion and seismic technology, prevailing weather and break-up conditions and access to our drilling locations, commodity prices, royalty regimes and exchange rates, the application of regulatory 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 our ability 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 placed on the forward-looking statements because Spartan can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), incorrect assessment of the value of acquisitions, failure to realize the benefits of acquisitions, constraint in the availability of services, commodity price and exchange rate fluctuations, changes in legislation (including but not limited to tax laws, royalty regimes and environmental legislation), adverse weather or break-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 to changes 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 in Spartan'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 any forward-looking information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws. The forward looking information contained in this 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 this presentation was made as of the date of this presentation and was provided for the purpose of providing further information about Spartan's anticipated future business operations. Spartan disclaims any intention or obligation to update or revise any FOFI contained in this presentation, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law. Readers are cautioned that the FOFI contained in this presentation should not be used for purposes other than for 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 gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All BOE conversions in the report are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil. 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’s total working interest reserves before the deduction of any royalties and including any royalty interests of the Company. The recovery and reserve estimates of Spartan’s crude 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 crude oil, 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 over the 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 of wells, 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 wells or 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 locations and probable locations are derived from the applicable engineering evaluation and account for drilling locations that have associated proved and/or probable reserves, as applicable. 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 on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Of the >2,500 gross drilling locations identified by Spartan, 464 are proved locations, 322 are probable locations and >1,700 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 we will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which 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, 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, 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 measures may not be comparable to similar measures presented by other issuers. Funds flow from operations, excess cash flow, operating netback, development capital, net debt and net debt exclusive of finance lease obligations are not recognized measures under IFRS. Management believes that in addition to net income (loss), funds flow from operations, operating netback, development capital, net debt and net debt exclusive of finance lease obligations are useful supplemental measures that demonstrate the Company’s ability to generate the cash necessary to repay debt or fund future capital investment. Investors are cautioned, however, that these measures should not be construed as an alternative to net income (loss) determined in accordance with IFRS as an indication of Spartan’s performance. Spartan’s method of calculating these measures may differ from other companies and accordingly, they may not be comparable to measures used by other companies. Cash flow from operating activities is calculated 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 in non-cash working capital, transaction costs and decommissioning obligation expenditures incurred. Operating netback is calculated based on oil and gas revenue less royalties and 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 waterflood expenditures and acquisitions. Net debt is calculated as bank debt plus trade and other liabilities plus finance lease obligations less current assets. Net debt has been presented exclusive of finance lease obligations, as Spartan believes that such measure is useful to evaluate Spartan’s financial liquidity. Estimated net debt excludes the outstanding principal amount of finance lease obligations. Estimated net debt as at December 31, 2017 does not include discretionary land, seismic or EOR spending in 2H 2017.