INVESTOR PRESENTATION Spartan Delta Corp. (SDE: TSXV)

March 26, 2021 SPARTAN DELTA CORPORATE STRATEGY Building a Sustainable Energy Company for Global Investors

DISCIPLINED CONSOLIDATOR Building towards >100,000 BOE/d

WEST-CENTRAL ALBERTA DEEP BASIN – Liquids-Rich ALBERTA MONTNEY – Oil-Weighted ▪ Low base decline <20% with $4,000/boepd ▪ Well delineated acreage position capital efficiency (1) and IRRs (1) >200% ▪ Drill ready inventory with owned ▪ Drill ready inventory with owned infrastructure infrastructure ▪ Organic growth with top tier Montney ▪ Asset sustaining capital <18% of NOI (1)(2) economics DISCIPLINED CONSOLIDATOR

MODERN ENERGY COMPANY SHAREHOLDER RETURN DRIVEN ESG ROI ▪ Strong Indigenous partnerships LEADERSHIP ▪ Strong balance sheet: $100MM undrawn bank line ▪ Gender diverse leadership and workforce ▪ Internally funded organic growth ▪ Developing a strategy & goals for emissions reduction ▪ Forecasting 2021 $38MM Free Funds Flow (1)(2) and $115MM YE Net Surplus (1)(2)

ESG LEADERSHIP ROI

March 26, 2021 2 1) See “Non-GAAP Measures” in Disclaimers 2) Corporate NOI estimate, based on Spartan Budget Price Deck as defined on slide 36 COMPANY OVERVIEW Spartan Delta Corp.

ALBERTA MONTNEY: ▪ Oil-weighted Montney focus Capitalization (as at March 25, 2021) ▪ Additional consolidation opportunities Spartan Delta Corp. TSX-V SDE ▪ Oil and Liquids-Rich Montney drilling upside Share Price (1) $/sh 4.04

Market Capitalization (basic) (1) $MM 460.2

Common Shares Outstanding (basic) MM 113.9

Net Debt (as at Dec 31, 2020) (2) $MM 12.3

Estimated YE 2021 Net Debt (Surplus) (2)(3) $MM (115)

Insider Ownership (basic) % 13.5

Dilutive Instruments

Warrants, ITM Options and Share Awards (4) MM 21.2 Zero Coupon Convertible Note (maximum issuance) (5) MM 6.5 Dilutive Proceeds $MM 26.3

Fully Diluted Shares Outstanding MM 141.6 WEST-CENTRAL DEEP BASIN: ▪ Cretaceous Oil and Liquids- Rich Gas focus ▪ Additional consolidation opportunities ▪ Spirit River and Cardium drilling upside

March 26, 2021 3 1) Share price as at closing on March 25, 2021 4) Excludes ~1.10MM out-of-the-money Options with an exercise price of $4.08/sh 2) See “Non-GAAP Measures” in Disclaimers 5) Assumes maximum issuance at conversion of $7.67/sh 3) See “Forward Looking Statements” in Disclaimers YE 2020 HIGHLIGHTS Optimization of Production and Cost Reductions Generate Material Free Funds Flow in 2020

Actuals Q1 2020 Q2 2020 Q3 2020 Q4 2020 FY 2020 Crude Oil % 10% 1% 1% 1% 1% Low-cost production optimization Current (3) Condensate % - 4% 4% 4% 4% offset declines in H2

Natural Gas Liquids (NGLs) (1) % 7% 25% 26% 26% 26%

Natural Gas % 83% 70% 69% 69% 69%

Average Production boe/d 251 8,906 26,282 26,010 15,421

Operating Expenses $/boe 22.57 6.96 6.10 5.68 6.11

Transportation $/boe - 1.38 1.34 1.37 1.36

Royalties % 0.4% 6.5% 8.5% 10.5% 9.0%

Operating Netback $/boe (4.33) 5.90 8.32 9.59 8.46 18% reduction in OPEX since West- Central Alberta Deep Basin G&A $/boe 37.76 1.48 1.50 1.48 1.64 acquisition (7% reduction Q3 to Q4)

Interest $/boe (3.48) 0.23 0.26 0.19 0.21

Adjusted Funds Flow (2) $MM (1.5) 2.8 14.4 16.8 32.5

Capital Expenditure (net of A&D) $MM 0.38 1.0 1.2 14.0 16.8

Well Count # 0 0 0 4 4

Free Funds Flow (2) $MM (1.9) 1.7 13.1 2.8 15.7

Exit Net Debt (Surplus) (2) $MM (21.7) 26.2 14.5 12.3 12.3

March 26, 2021 4 1) See “Oil and Gas Advisories” in Disclaimers 2) See “Non-GAAP Measures” in Disclaimers 3) As of March 24, 2021 WEST-CENTRAL ALBERTA DEEP BASIN LIQUIDS-RICH DEVELOPMENT Free Funds Flow Generating Core Area - Driven by Industry Leading Capital Efficiencies

West-Central Alberta Deep Basin Asset Characteristics Tidewater BRC 185 mmscf/d Deep Cut Top Quality Resource: ▪ Top tier, delineated liquids-rich Spirit River and condensate-rich Cardium gas development ▪ Primary targets: Falher, Notikewin and Cardium sands SDE O’Chiese Nees-Ohpawaganu’ck 10-09 ▪ 425 net risked Spirit River and Cardium locations (1) 230mmscf/d Deep Cut (25% WI)

CVE Sand Creek Land: 75 mmscf/d (9.6% WI) SDE 5-5 (2) ▪ >54,000 net acres of delineated Spirit River and Cardium land 1,000 bbl/d

▪ Additional consolidation opportunities in the vicinity leveraging off CVE Alder 75 mmscf/d infrastructure advantage (20% WI) SDE 2-10 SDE 13-5 Infrastructure: 20 mmscf/d 74 mmscf/d ▪ Significant owned and operated strategic infrastructure in place to SDE 9-3 SDE 5-3 45 mmscf/d grow production >40,000 boe/d with minimal incremental capital 20 mmscf/d SDE 6-21 40 mmscf/d ▪ Deep-cut gas processing enhances margins on liquids recovery SDE 8-4 20 mmscf/d ▪ Direct tie-in to NGTL with optionality on liquids marketing ▪ Tangible operating cost savings as throughput increases over time

OBE Crimson Low Decline Base Production: SDE 4-29 60 mmscf/d 350 bbl/d ▪ Current base decline of 19%

Material Free Funds Flow Driven by Low Sustaining Capital: ▪ Sustaining capital of $30 million vs. corporate NOI (3)(4) of $170 million ~$4,000/flowing barrel capital efficiency (1)

Spartan Working Interest Gas Plant Spartan Wells Pembina HVP / LVP Third Party Gas Plant Spartan Pipelines Tidewater Pipelines Spartan Compressor Station / Battery NOVA NGTL Keyera Pipelines March 26, 2021 5 1) See “Oil and Gas Advisories” in Disclaimers 4) See “Non-GAAP Measures” in Disclaimers 2) As of December 31, 2020 3) Estimate, based on Spartan Budget Price Deck as defined on slide 36 YE2020 RESERVES HIGHLIGHTS Extended Reach Horizontals (“ERH”) Drives Step Change in F&D and Development Economics

YE2020 West-Central Alberta Deep Basin Reserves Highlights: Oil Natural Gas NGL's Total NPV10 (1) ▪ Spartan’s Year-End 2020 Reserves demonstrate the superior Reserves Category (MMbbl) (Bcf) (MMbbl) (MMboe) ($MM) economics of its West-Central Alberta Deep Basin core area: Proved Developed Producing 0.9 277.3 20.2 67.3 375.9 ▪ Recycle Ratio (1) of 2.4x (TP) and 2.9x (TPP) Total Proved 2.6 557.0 39.6 135.0 777.3 Total Proved + Probable 5.0 847.8 60.6 206.9 1,078.1 ▪ F&D (1) of $3.94/boe (TP) and $3.35/boe (TPP) ▪ 99% of the Reserve NPV10 (1) is within the West- Total (MMboe) (1) 250 Central Alberta Deep Basin core area; newly acquired 206.9 Alberta Montney core area to be included in the next 200 reserves update ▪ Reserve plan matches Spartan’s current business plan; modest 150 135.0 capital expenditures to maintain significant free cash flow: 100 ▪ Optimized FDC (1) of $267MM (TP) and $417MM 67.3 (TPP); only 1.9x (TP) and 3.0x (TPP) of Spartan’s (MMboe) Reserves 50 current Adjusted Funds Flow (2) Guidance ($139MM) 0 ▪ Highly economic and achievable development plan delivers PDP TP TPP $620MM of NOI (2) after capital in McDaniel’s 5-year reserves model (1) ▪ 72% of booked and 56% of total inventory are now NPV10 ($MM) $1,200 $1,078 configured as ERH locations $1,000 ▪ Material future reserves growth potential remains unbooked: $777 $800 ▪ Only booked reserves in four main formations (Cardium, Falher A, Falher B, and Notikewin) $600 $376 (1) $400 ▪ Over 425 Spirit River and Cardium locations remain ($MM) NPV10 in inventory (>75% unbooked) $200 ▪ Spartan’s YE2020 Reserves do not include any values $0 attributable to transactions announced in 2021 PDP TP TPP

March 26, 2021 6 1) See “Oil and Gas Advisories” in Disclaimers 2) See “Non-GAAP Measures” in Disclaimers WEST-CENTRAL ALBERTA DEEP BASIN 2020 YE RESERVE AUDITOR MODEL McDaniel’s TPP Bookings Generate $620 Million of NOI (2) After Capital Expenditure in First 5 Years

TPP Production Forecast YE 2020 TPP NOI (2) Summary (5yr McDaniel’s Forecast) Achievable Development with Steady Production Growth TPP Development Generates Material Net Operating Income at Reserve Auditor Pricing

Spartan can show reserve and value growth for the next 5+ years:

▪ 101 Net locations booked (63 PUD, 38 PBUD), TP FDC (1) = $266.5MM, TPP FDC (1) = $417.3MM ▪ Additional 425 locations in inventory with strong economics (>75% unbooked) ▪ Ability to increase capital expenditures and accelerate growth within cash flow

March 26, 2021 7 1) See “Oil and Gas Advisories” in Disclaimers 2) See “Non-GAAP Financial Measures” in Disclaimers WEST-CENTRAL ALBERTA DEEP BASIN INVENTORY SUMMARY Robust Inventory with Years of Future Growth at High Rates of Return

Updated Inventory: YE2020 Inventory Summary (1) ▪ As at year end 2020, prior to acquisitions announced on February 16, 2021 ▪ Rigorous review of every location within the West-Central Alberta Deep Zone Booked Unbooked Total % ERH Basin inventory Cardium 37 121 158 65% Spirit River (2) 57 211 268 52% ▪ In 2020, Spartan reconfigured its reserves inventory to capture Extended Total Cardium & Spirit River 93 332 425 57% Reach Horizontal (ERH) locations where available Other (6) 8 157 165 53% Total 101 489 590 56% Highly Economic and Efficient Inventory: ▪ Reconfiguring to ERH has made locations more economic. Compared with 1.0-mile locations, 2.0-mile extended reach horizontals: ▪ Require 1.25x more CAPEX Cumulative Distribution of Location IRR (3)(5) ▪ 1.80x higher 1P/2P reserves By Booking Category 100% ▪ Results in 1.7x higher IRR (5) 90%

▪ YE2020 Inventory is now ~56% extended reach 80%

▪ Spartan has identified ~200 net Spirit River and Cardium locations with IRRs 70% (3)(5) exceeding 100% 60% What Drives the Robustness of the Inventory? 50% ▪ High quality, over pressured reservoir with high liquids yield 40%

▪ Infrastructure is built out: full cycle economics require little to no 30% Percentage of Inventory (%) Inventory of Percentage infrastructure capital 20% 5 Year Plan | 13 net wells/yr | Mean IRR = 306% Booked | 93 net wells | Mean IRR = 216% ▪ Deep cut processing enhances liquids recovery 10% Unbooked | 218 net wells | Mean IRR = 111%(4) ▪ Field optimization since acquisition has reduced operating costs and 0% increased margins 0% 100% 200% 300% 400% 500% IRR (%)

March 26, 2021 8 1) Net locations rounded to the nearest whole number 4) Unbooked excludes Falher D/E and Wilrich 2) Spirit River includes Notikewin, Falher A/B/D/E and Wilrich 5) See “Non-GAAP Measures “in Disclaimers 3) Based on Spartan Budget Price Deck, as seen on slide 36 6) Other includes 8 Booked PRA locations, and all other zones in West-Central Alberta Deep Basin WEST-CENTRAL ALBERTA DEEP BASIN SPIRIT RIVER TYPE WELL Operational Efficiencies and ERH Drilling Drives Step Change in Well Economics

Highlights: ▪ Next 5-year estimated development capital efficiency (4): ~$4,000/boepd ▪ >88 locations with less than 10-month payout (4) ▪ Considerable room for future reserve growth: 22% booked ▪ Diversification potential through complementary zones (Falher D/E, Wilrich excluded) ▪ Diverse land base: 58% Crown / 42% IOGC

1P Type Curve and Economics (1)

Spirit River Single Well 1P Economics (2)

Inputs Tier 6+ Tier 5 Tier 3-4 1P Reserves Mboe 1,545 1,069 673 Gas MMcf 6,657 4,620 2,841 Cond Mbbl 52 36 22 NGLs Mbbl 383 201 131 % Liquids % 28% 22% 23% DCET C$M $4,465 $3,912 $3,454 Average lateral length mi 1.9 1.7 1.4

Outputs NPV10 C$M $8,692 $5,866 $3,186

1 IRR % 271% 221% 120% Payout Years 0.6 0.7 1.2 Capital Efficiency $/boepd $3,044 $4,098 $5,611 Net Location Count (3) # 37 31 71 % of Inventory % 21% 18% 41%

March 26, 2021 9 1) See “Oil and Gas Advisories” in Disclaimers, Type Curve prepared by McDaniel, Dec. 2020 4) See “Non-GAAP Measures” in Disclaimers 2) Based on Spartan Budget Price Deck as seen on slide 36; Jan 1, 2021 Effective Date 3) Includes Falher B, Notikewin and select Falher A locations WEST-CENTRAL ALBERTA DEEP BASIN CARDIUM TYPE WELL Over-Pressured Cardium Provides Compelling Condensate-Rich Economics

Highlights: Inventory IRR of Cardium ▪ Next 5-year estimated development capital efficiency (3): ~$5,000-6,000/boepd ▪ >107 locations with less than 1 year payout (3) ▪ 65% of inventory is booked as ERH ▪ Considerable room for future reserves growth: 24% booked ▪ Diverse land base: 63% Crown / 37% IOGC

1P Type Curve and Economics (1)

Cardium Average Tier Single Well 1P Economics (2)

Inputs Tier 3 Tier 1 1P Reserves Mboe 963 579 Oil Mbbl 62 67 Gas MMcf 3,097 1,764 Cond Mbbl 36 19 NGLs Mbbl 349 199 % Liquids % 46% 49% DCET C$M $4,222 $3,595 Average lateral length mi 1.9 1.4

Outputs NPV10 C$M $6,803 $3,983 IRR % 212% 136% Payout Years 0.7 0.9 Capital Efficiency $/boepd $5,357 $6,846 Net Location Count # 57 50

March 26, 2021 1) See “Oil and Gas Advisories “in Disclaimers, Type Curve prepared by McDaniel, Dec. 20 10 2) Based on Spartan Budget Price Deck as seen on slide 36; Jan 1, 2021 Effective Date 3) See “Non-GAAP Measures” in Disclaimers WEST-CENTRAL ALBERTA DEEP BASIN WINTER DRILLING RESULTS Winter Drilling Program – Exceeding Expectations

Highlights: 102/16-23-045-09W5 SDE 10-09 Deep Cut Gas Plant ▪ 8 well program: six extended reach horizontal Spirit River wells, one 2.0- Cardium, 2 mile HZ mile Cardium well and one 1.0-mile Spirit River 100/06-25-044-10W5 Falher B, 1.6 mile HZ ▪ 8 wells are now on production, with several wells producing at restricted rates to manage declines and operational efficiencies 102/04-25-044-10W5 ▪ 7 of the 8 locations feed the Spartan operated 10-09 deep cut gas plant Falher B, 2 mile HZ 103/04-25-044-10W5 ▪ All operations were completed successfully under budgeted DCET cost Notikewin, 2 mile HZ

100/07-01-044-10W5 Spartan Production – Net Sales Falher B, 1.8 mile HZ 35,000 102/08-01-044-10W5 100/01-26-044-07W5 Falher B, 1.8 mile HZ Notikewin, 2 mile HZ

30,000 102/01-16-043-09W5 Falher B, 1 mile HZ 25,000

20,000

15,000

10,000 Net Sales Production (boe/d) Production Sales Net 5,000 DCET (1) IP30 (2) IP60 (3) 0 2020-10 2020-11 2020-12 2021-01 2021-02 ($MM) (boe/d) (boe/d) Q4/Q1 Program $3.8 1,523 1,642 Spartan Base Q4 Drilling Q1 Drilling

March 26, 2021 11 1) Average DCET over 8 well program; including 6 two-mile Spirit River wells, 1 Cardium two-mile and 1 single-mile Spirit River 2) Average IP30 Production Sales Estimates for 8 Spirit River wells 3) Average IP60 Production Sales Estimates for 6 Spirit River wells SUMMARY OF RECENT ACQUISITIONS Acquisition of High-Quality Assets Establishes Second Core Development and Consolidation Area

Spartan has entered into three definitive acquisition agreements which execute upon its consolidation strategy.

Alberta Montney Core Area Entry Acquisitions: SDE Gold Creek ▪ Gold Creek Oil Montney with the corporate acquisition of Inception Exploration Processing Facility ▪ Simonette Liquids-Rich Montney and Spirit River with assets coming out of a CCAA restructuring Gold Creek West-Central Alberta Deep Basin Core Area Expansion Acquisition: Simonette Gas Plant ▪ Willesden Green, Cardium and Spirit River Assets with production, royalties, facilities and land Summary of Acquisitions

Production - Feb 16, 2021 (22.5% Oil, 4.5% Condensate, 8% NGLs) boe/d 9,700 Proved Reserves (1) Mboe 91,517 Simonette Proved plus Probable Reserves (1) Mboe 215,381 Run Rate Net Operating Income (2) $MM 50.0 Total Land net acres 235,393 Total Montney Land net acres 85,388 Total Net Drilling Locations (1) # 414 Total Net Montney Drilling Locations (1) # 343

Metrics of Acquisitions SDE O’Chiese Nees- Alder Gas Plant Ohpawaganu’ck Gas Plant Production - Feb 16, 2021 $/boe/d 15,247 Proved Reserves (1) $/boe 1.62 Proved plus Probable Reserves (1) $/boe 0.69 Sand Creek Gas Plant Multiple of Run Rate Net Operating Income (2) x 2.95

Total Purchase Price

Cash consideration, after estimated adjustments $MM 18.4 Willesden Common Shares $MM 96.7 Green Convertible Unsecured Promissory Note (Principal - $50.0MM) (3) $MM 25.0 Working Capital Deficit $MM 7.8 Total consideration (estimate) $MM 147.9 Spartan (Pre-acquisitions) Inception Exploration Simonette Acquisition Willesden Green Acquisition March 26, 2021 12 1) See “Oil and Gas Advisories” in Disclaimers 2) Run Rate NOI based on Spartan Budget Price Deck as seen on slide 36, See Non-GAAP Measures in Disclaimers 3) Convertible at Spartan’s election after second anniversary at greater of $7.67/sh or 10-day VWAP of SDE equity on conversion date MATERIAL ENTRY INTO THE ALBERTA MONTNEY FAIRWAY Introducing Spartan’s New Core Area for Development and Consolidation

Best in Class Resource: Spartan Montney Lands Velvet Energy ▪ One of Canada’s most prolific plays with attractive economics Leucrotta Hammerhead Resources across a broad range of commodity prices Pipestone Energy ▪ Delineated and repeatable development - well suited to Shell Paramount Resources Spartan’s low-cost execution skill set Advantage ▪ Higher oil and liquids rates provide commodity diversification to Arc Kelt the business NuVista Seven Generations Distinction / Kiwetinohk Tourmaline Near-term Development Pathway to >25,000 boepd of Oil- XTO Weighted Alberta Montney Production: Whitecap Cenovus ▪ Deep inventory with drill ready locations Canadian Natural Leucrotta ▪ Spartan owned infrastructure in place to accommodate growth Arc without incremental spend Advantage Ovintiv Kelt Tourmaline ▪ Multiple egress pathways provide flexible marketing options

Grande Prairie Inception Acquisition (Gold Creek): Pipestone ▪ Current Production ~4,200 boe/d (~53% liquids) (1)(3) Gold Creek Velvet ▪ Infrastructure in place to grow to 20,000 boe/d Shell Paramount ▪ Near-term focus of development NuVista CNRL

Simonette Acquisition: Hammerhead ▪ Current production ~4,500 boe/d (17% liquids) (2)(3) ▪ Infrastructure in place to grow to 25,000 boe/d Seven Whitecap ▪ Mid-term development focus Generations

January Land Acquisition: XTO Ovintiv

▪ 26 sections of Montney rights Cenovus Distinction / Simonette Kiwetinohk ▪ Future development potential upon expansion of infrastructure footprint

March 26, 2021 13 1) 43% crude oil, 10% NGLs and 47% conventional natural gas 2) 4% crude oil, 9% condensate, 4% NGLs and 83% conventional natural gas 3) As of March 12, 2021 GOLD CREEK MONTNEY DEVELOPMENT Acquisition of Inception Exploration Anchors Second Core Development and Consolidation Area

Inception Asset Characteristics

CITY OF GRANDE PRAIRIE Bezanson Top Quality Resource: ▪ Top tier Montney asset in the core of the Alberta Montney Oil Pipestone development fairway ▪ >128 net risked Middle Montney locations (1)(2)

Land: SDE Battery & Gas Processing: • 10,000 bopd ▪ >30,000 net acres of delineated Montney land • 5,000 bwpd • 40 mmscf/d sour gas ▪ Additional consolidation opportunities in the vicinity leveraging off infrastructure advantage

Infrastructure: ▪ Significant 100% working interest (“WI”) infrastructure in place to grow production >20,000 boe/d with minimal incremental capital Elmworth

▪ Processing optionality: dual gas plant connection, ability to add third SDE Sales Compressor connection with minimal capital

▪ Sales optionality: dual connection to NOVA and Alliance Gold Creek ▪ No minimum-volume processing commitments ▪ Many components already in place for a future Spartan gas plant

State of Readiness: SemCams Wapiti CNRL Gold Creek ▪ Drill ready, multi-well pad development set to begin in 2021 Keyera Wapiti

Wapiti

Spartan Montney WI Lands Acquisition Montney Wells CNRL Gold Creek System Montney Wells SemCams System Acquisition Infrastructure Keyera System

March 26, 2021 1) See “Oil and Gas Advisories” in Disclaimers 14 2) Assumes 300m well spacing and scaling up of frac density GOLD CREEK MONTNEY Oil-Weighted Development Across a Well Delineated Land Base

▪ Over 160m of net reservoir situated in the over-pressured (>10 kPa/m) oil prone fairway of the Alberta Montney CITY OF GRANDE PRAIRIE ▪ De-risked future development with 21 horizontals drilled to date across land base ▪ Single layer Middle Montney development; potential for “wine-rack” style geometry currently being modelled with wells in both Middle and Lower Middle Montney Oil ▪ Evolution in completion design from 2013 to 2020 demonstrates significant (>400 bbls/MMcf) improvement in deliverability with implementation of tighter stage spacing and increased tonnage ▪ 2021 budget includes 3-4 net wells in TWP 69-05W6 targeting the Middle and 8-36 HZ Lower Middle Montney; finalizing completion designs for summer program A

A 100010307006W600 100041906905W600 100162606905W600 A’ A’

Gamma NPHI DPHI RESD Gamma NPHI DPHI RESD Gamma NPHI DPHI RESD TOP MNTN

Gas Condensate (~50 bbls/MMcf)

MIDDLE Montney

D2 Lower Spartan Montney WI Lands SDE Montney Wells Pressure Gradient MIDDLE Industry Montney Wells Montney ▪ 100/08-36-069-05W6 HZ drilled from 7-34 pad; on production Dec. 2019 LWR ▪ Cumulative oil to date >185 mbbls w/ peak monthly rate of 900 bbls/d LOWER Montney ▪ 1.8-mile lateral, completed with 160 stage 50t/stage multi-stage frac; BELLOY ▪ Step change in results compared to offsets with 75 stages and lower tonnage Middle Montney Landing Depth ▪ Basis for development in 2021/22 program March 26, 2021 15 SIMONETTE MONTNEY DEVELOPMENT Acquisition of Simonette Asset Bolsters Second Core Development and Consolidation Area

Simonette Asset Characteristics

Undercapitalized, High-Quality Resource: Alliance Connection ▪ The Simonette asset represents a significant resource footprint within the Alberta Montney fairway with delineated and attractive development opportunities across liquids-rich, gas and oil prone horizons ▪ Primary target of Middle Montney; Lower Montney has also been Keyera Simonette identified as highly prospective Kanata Simonette 13-11 Plant: (1) • 120mmscf/d capacity ▪ >214 net risked Middle Montney locations • 30mmscf/d throughput • 50% WI Land: ▪ >54,000 net acres of delineated Montney land ▪ Additional consolidation opportunities in the vicinity leveraging off infrastructure advantage

Infrastructure: ▪ 50% WI in a 120 mmcf/d natural gas plant allows for production growth >25,000 boe/d ▪ Sales optionality: dual connection to NOVA and Alliance

Low Decline Base Production: ▪ Stable base decline of <20%

Post CCAA Optimization Potential: Spartan Montney WI Lands Acquisition Montney Wells Montney Wells ▪ Virtually no capital has been deployed in the last 3 years across the assets due to financial constraints of previous operator ▪ Spartan intends to apply core cost reduction and field optimization principles to the assets to enhance margins and offset declines ahead of development beyond 2021

March 26, 2021 16 1) See “Oil and Gas Advisories” in Disclaimers SIMONETTE MONTNEY Diverse Montney Opportunity Set Within a Large Underexploited Resource Base

▪ Over 100m net reservoir of Montney resource at predominantly higher than normal reservoir pressure (> 10 kPa/m)

▪ De-risked future development with 38 horizontals (34 gas to liquids-rich and four oil) drilled to date across 62,000 acres of Montney rights

4-34 HZ ▪ Analogue wells with lower landing depths in the Middle Montney demonstrate potential for higher liquids yields in both gas and liquids fairways

▪ Modern completion design with increased length and tonnage in combination

with lower landing depth yield significant improvement in deliverability 9-18 PAD Oil ▪ Additional opportunities identified in the Spirit River within the core of the asset (>100 bbls/MMcf)

A’ A’ A 100111606127W500 100133606127W500 100012906126W500 Gamma Gas TOP Gamma NPHI DPHI RESD Gamma NPHI DPHI RESD NPHI DPHI RESD (<30 bbls/MMcf) MNTN A

MIDDLE Montney

D2

Lower MIDDLE Montney

Spartan Montney WI Lands SDE Montney WI Wells Pressure Gradient Industry Montney Wells Liquids-Gas Ratio Spartan Other Lands

LWR LOWER Montney ▪ 100/04-34-062-27W5 HZ drilled in 2017 demonstrates increased deliverability compared to vintage wells drilled in oil fairway ▪ 9-18-62-02W6 pad – two wells drilled in 2016-2019 w/ lower landing depth in

BELLOY Historical Middle Montney Landing Depth similar liquids window using modern completion techniques Proposed Middle Montney Landing Depth

Lower Montney Landing Depth March 26, 2021 17 2021 GUIDANCE Adjusted Funds Flow Sensitivities

2021 Guidance (1)(2) West-Central Alberta Deep Basin Assets Drive Robust Cash Generation: ▪ 100% of natural gas production priced at AECO Average Production boe/d 35,500 - 37,500 ▪ West-Central Alberta Deep Basin sustaining capital (3) requirement: (3) (2) Crude Oil % 4 <$30 million vs. corporate NOI of $170 million ▪ Forecast 2021 Corporate Payout Ratio (3) : ~73% (2) Condensate % 4 ▪ Continued focus on operational efficiencies to drive higher margins NGLs % 23 (2021 West-Central Alberta Deep Basin OPEX forecast represents a Natural Gas % 69 >26% reduction since acquisition in June 2020) ▪ Free Funds Flow (3) will be applied to continued consolidation of (3) $/boe 12.74 Operating Netback quality assets at attractive metrics Adjusted Funds Flow (3) $MM 139

Capital Expenditures (4) $MM 101 Free Funds Flow (3) $MM 38 2021 Adjusted Funds Flow Sensitivity (1)(2)(3) Net Debt (Surplus) (3) $MM (115) WTI US$/bbl $50 $55 $60

Edm. Oil Diff US$/bbl $4 $4 $5 2021 Capital Allocation % Wells Edm. Cond Diff US$/bbl $1 $1 $3

West-Central Alberta Deep Basin 65% 13 Conway Propane US$/GAL $0.65 $0.70 $0.75 Alberta Montney - Gold Creek 35% 4 FX US/C 1.27 1.26 1.25

$/GJ $2.50 $123 $132 $141

AECO $/GJ $2.75 $131 $139 $147 $/GJ $3.00 $138 $146 $154

March 26, 2021 18 1) See “Forward Looking Statements” and “FOFI” in Disclaimers 4) Excluding A&D 2) Based on midpoint production of 36,500 boe/d and Spartan Budget Price Deck as seen on slide 36 3) See “Non-GAAP Measures” in Disclaimers SPARTAN SUSTAINABILITY Environmental, Social & Governance

Canada is a world leader with respect to producing sustainable energy responsibly

Environment: ▪ Spartan is committed to industry leading environmental practices: ▪ Spartan has ~400 solar panels, with solar power generation at nearly every pad site within its core operating area ▪ Spartan has participated in or operated 36 wells and one facility abandonment since March 2020 and progressed towards reclamation certification on over 100 abandoned locations ▪ Achieved a 100% satisfactory rating with the AER in 2020 vs. industry average of 78% ▪ Spartan assets generated over 17,544 tCO2e credits in 2019 and a further 13,247 tCO2e credits in 2020 from:

▪ High to low bleed instrumentation conversion

▪ Converting fuel gas chemical pumps to solar driven

▪ Fuel gas to instrument air conversion

▪ Fuel gas instrumentation to solar powered instrumentation

Social: ▪ Spartan has implemented health and safety COVID-19 protocols into its operations ▪ Based on the WCB Industry 6300 for 2020, Spartan ranks 1 out of 256 employers in the Large Business Experience Rating (ER) program (1)

Governance: ▪ Spartan is significantly aligned with shareholders with 13% Insider Ownership (basic) ▪ Diversity – 30% Female in Management Positions & 42% Female Workforce

Spartan Delta wellsite solar power generation

March 26, 2021 19 1) As per the Workers’ Compensation Board – Alberta Employer Report Card INDIGENOUS PARTNERSHIPS Committed to Sustainable and Responsible Resource Development

O’Chiese First Nation: ▪ Spartan has a partnership with the O’Chiese First Nation based on responsible development of oil & gas resources on the O’Chiese First Nation lands ▪ Spartan prioritizes First Nation owned and operated business with respect to its operations ▪ Spartan has created a soci-economic plan with the O’Chiese to create long-term social benefits for the First Nation

Leading Environmental Stewardship on First Nation lands: ▪ Spartan, together with the O’Chiese First Nation, have created an industry leading Abandonment & Reclamation Program to protect Indigenous lands for future generations ▪ The ARO program outlines and commits Spartan to timely abandonment & reclamation of all wells on the O’Chiese First Nation lands

▪ Spartan has also committed to working with both the Saddle Lake First Nation and Whitefish (Goodfish) Lake First Nation to abandon and reclaim wells on First Nation lands

March 26, 2021 20 MARKETING & RISK MANAGEMENT High Torque to Strengthening AECO Fundamentals

Natural Gas Exposure – 100% AECO: ▪ Spartan is uniquely positioned with 100% exposure to AECO pricing, and no economic burden of transport to underperforming markets ▪ Natural gas production is hedged approximately 28% in 2021

Natural Gas Fundamentals continue to be positive: ▪ Natural gas power generation is the largest component of the North American power stack and will continue to grow as coal is phased out

Current Operating Capacity by Technology

Coal Wind Solar Other Nuclear Natural Gas Source: ARM Energy

▪ Alberta gas egress coupled with increasing Western Canadian Sedimentary Basin gas demand paints an attractive story for AECO versus other markets

March 26, 2021 21 INVESTOR HIGHLIGHTS Platform for Acquisitive Growth and Free Funds Flow Generation

Experienced team with a record of efficient capital discipline and value creation through consolidation

Material position in the Spirit River, Cardium and Montney, three of Canada’s most prolific plays

Two Core Areas – West-Central Alberta Deep Basin and Alberta Montney

Targeting internally funded organic growth and material free funds flow

Balance Sheet strength to fund further consolidation

Modern company with a clean operating platform and minimal ARO overhang

Owned infrastructure footprint provides opportunistic tuck-in consolidation potential

Deep inventory of economic drilling on strip pricing – active drilling program in 2021

March 26, 2021 22 Appendix

March 26, 2021 23 WEST-CENTRAL ALBERTA DEEP BASIN Asset Quality Drives Top Tier Capital Efficiencies and Sustainable Free Funds Flow

▪ Targeting liquids-rich Spirit River and liquids-rich gas and oil Cardium ▪ Favorable subsurface properties: Deep Basin ✓ Situated in the over-pressured deep basin fairway Fairway

✓ Considerably higher liquids yield than most Spirit River assets Pembina

▪ Multiple stacked targets in the Spirit River provide significant resource development opportunities, including maximizing recoveries and surface pad synergies

▪ 10+ years of de-risked, highly economic Spirit River and Cardium Brazeau locations across >130,000 (1) net acres of land in West-Central Alberta

A A’ 100132304410W500 100030404509W500 100013304309W500 Gamma NPHI DPHI Gamma NPHI DPHI Gamma NPHI DPHI Alder Flats

A

Cardium Cardium Ferrier

A’ Willesden Green Baptiste

Falher A Falher A

Falher B Falher B

Wilrich Wilrich

Spartan Lands O’Chiese First Nation Spirit River Well Cardium Well

March 26, 2021 24 1) As of December 31, 2020 ANALYST COVERAGE & CONTACT INFORMATION

Institution Analyst EXECUTIVE OFFICE STOCK EXCHANGE LISTING The TSX Venture Exchange ATB Capital Markets Patrick O’Rourke Spartan Delta Corp. 500, 207 – 9th Avenue SW Trading Symbol: SDE.V Calgary, Alberta T2P 1K3 BMO Capital Markets Ray Kwan INVESTOR INFORMATION P: 403 265 8011 W: www.spartandeltacorp.com Visit our website Cormark Securities Garett Ursu W: www.spartandeltacorp.com TRANSFER AGENT or contact Desjardins Capital Markets Chris MacCulloch Investor Relations Odyssey Trust Inc. E: [email protected] 1230 – 300 - 5th Avenue SW Eight Capital Phil Skolnick Calgary, Alberta T2P 3C4 CORPORATE CALENDAR P: 587 885 0960 Haywood Capital Markets Christopher Jones May 14, 2021 AUDITORS First Quarter 2021 Results National Bank Financial Dan Payne PricewaterhouseCoopers LLP Calgary, Alberta Paradigm Capital Adam Gill ENGINEERING CONSULTANTS Peters & Co. Limited Dan Grager McDaniel & Associates Consultants Ltd. Calgary, Alberta Raymond James Jeremy McCrea LEGAL COUNSEL Scotia Capital Cameron Bean Stikeman Elliott LLP Stifel - FirstEnergy Cody Kwong Calgary, Alberta

TD Securities Aaron Bilkoski

March 26, 2021 25 MANAGEMENT TEAM & BOARD OF DIRECTORS MANAGEMENT TEAM

Richard McHardy ➢ Former President, CEO and co-founder of Spartan Energy, Spartan Oil and Spartan Exploration Executive Chairman & Director Fotis Kalantzis ➢ Former SVP and co-founder of Spartan Energy, Spartan Oil and Spartan Exploration President, CEO & Director Geri Greenall ➢ Former CFO and co-founder, Camber Capital Corp., former Portfolio Manager & Chief Compliance Officer, Canoe Financial CFO Thanos Natras ➢ Former Geoscience Manager, Spartan Energy, former VP Exploration, Arcan Resources VP Exploration Craig Martin ➢ Former Manager D&C, Spartan Energy and Spartan Oil VP Operations Randy Berg ➢ Former VP Land, Spartan Energy, former VP Business Development & Land, Renegade Petroleum VP Land Mark Hodgson ➢ Former VP Operations, Obsidian Energy, former VP New Ventures & Country Manager, Bankers Petroleum VP Corporate Development Brendan Paton ➢ Director, Canoe Point Energy, former Production Engineer, Shell Canada VP Engineering Ashley Hohm ➢ Former VP Finance, Kelt Exploration, former Manager Financial Reporting, Celtic Exploration VP Finance & Controller INDEPENDENT BOARD OF DIRECTORS

➢ Former Director of Spartan Energy, Spartan Oil, and Spartan Exploration  former President, Cypress Energy; Chairman & Donald Archibald CEO, Cequel Energy; President & CEO, Cyries Energy ➢ Former Director of Spartan Energy, Spartan Oil and Spartan Exploration  former Chairman, President & CEO, Big Horn Reg Greenslade Resources, Enterra Energy, Enterra Energy Trust, JED Oil; President & CEO, Tuscany International Drilling ➢ Founder and a principal of KO Capital Advisors  former Vice Chairman & Co-Head Energy Investment Banking, GMP Kevin Overstrom FirstEnergy ➢ Former SVP, Corporate and Business Development, Crescent Point Energy  Director of Southern Energy Corp., and Equinor Tamara MacDonald Canada ➢ Former Chairman & CEO, New Age (African Global Energy) Ltd.  former Executive Director & Officer, Marathon Oil and Steve Lowden Premier Oil

Elliot S. Weissbluth ➢ Former Chairman, Hightower Inc.  former Founder, Director & President, U.S. Fiduciary

March 26, 2021 26 SPARTAN ENERGY – SPARTAN OIL – SPARTAN EXPLORATION Western Canada’s Best-in-Class Performer: Proven Low-Cost Operator

▪ From 2010 through 2018, Spartan assembled and developed multiple high-quality assets throughout Central & Southern Alberta and Southeast Saskatchewan

▪ Through infill horizontal development drilling and its application of multi-stage frac technology, Spartan unlocked significant resource potential in both light and tight oil plays

▪ Developed a deep inventory of highly economic light oil drilling locations and waterflood projects capable of delivering sustainable growth and free cash flow

▪ Focused capital on high quality, long life, operated, multi-zone potential with existing infrastructure and capacity

▪ Spartan Exploration: grew production from ~400 boe/d to ~2,500 boe/d and sold to Penn West, outperforming the TSX Energy Index by ~90%

▪ Spartan Oil: sold to Bonterra for ~$480 million in 2013 after growing production to >4,000 boe/d

▪ Spartan Energy: sold to Vermilion Energy for C$1.4 billion in 2018 at a production level of 23,000 boe/d and independently evaluated P+P reserves of 113.5 MMBoe

March 26, 2021 27 THE SPARTAN DOMESTIC ADVANTAGE Domestic Operational Track Record

From 2014 to its sale to Vermilion Energy, Spartan Energy Management’s ability to acquire and efficiently integrate assets established itself as the lowest cost operator in the Southeast has been proven through past transaction activity Saskatchewan area

▪ Average DCET costs for Mississippian wells below area peers at ▪ Management steadily reduced operating costs following two $750k separate “acquisition cycles”

▪ Strong relationships with key service providers are intact and ▪ Spartan Energy completed 11 transactions (asset and corporate) in ensure efficiencies through preferential rates and pre-existing just under a four-year time frame, more than any other personnel corporation in the basin

Mississippian DCET Capex ($000’s) Spartan Energy - Operating Costs ($/boe)

$1,200 $22.00 $1,000 Acquisition OPEX $1,000 $900 $920 $20.00

$800 $750 $18.00

$600 $16.00

$400 $14.00

$200 $12.00

$0 $10.00 Spartan Energy Company 1 Company 2 Company 3 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1

(1) Peer group includes Vermilion, TORC, and Crescent Point 2014 2015 2016 2017 2018

March 26, 2021 28 SPARTAN ENERGY 263% Total Return and 33% CAGR | December 2013 – May 2018

Overview Relative Performance (Indexed to 100)

300 ▪ Spartan Energy completed the recapitalization of Alexander Energy Spartan in December 2013 and shortly after acquired Renegade Petroleum TSX Energy Post-recapitalization, in March 2014 250 Spartan consistently outperformed the TSX Energy Index ▪ Over a 4-year period, management grew production from ~650 200 boe/d to ~22,750 boe/d through an acquisition and development strategy 150

▪ During a period of significant uncertainty in the energy markets, management stewarded capital efficiently and delivered above 100 market shareholder returns 50 Dec-13 Jun-14 Dec-14 Jun-15 Dec-15 Jun-16 Dec-16 Jun-17 Dec-17

Production Growth Cash Flow Growth

$60.0 $0.60

25,000 150.0 ($/mmsh.) Share Per Flow Cash

20,000 120.0 Share Per Production (boe/d/mmsh.) $40.0 $0.40 15,000 90.0

10,000 60.0

$20.0 $0.20 Cash Flow Cash Flow ($mm)

Production Production (boe/d) 5,000 30.0

0 0.0 $0.0 $0.00 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 2014 2015 2016 2017 2018 2014 2015 2016 2017 2018

Total Production Production per Share Cash Flow Cash Flow per Share

March 26, 2021 29 HISTORICAL EV/DACF MULTIPLE COMPARISON Spartan Energy Corp. vs Premium Light Oil Peers (1)

16.0x Spartan Energy Corp.

Light Oil Peer Avg. (2) 14.0x The Spartan management team has historically traded at, or above, the premium light oil company average multiple (1)

12.0x

10.0x

8.0x Fwd EV/NTMFwd DACF Multiple (x) 6.0x

Light Oil Peer Avg.

4.0x

2.0x

Source: Factset Consensus Estimates (-) March 26, 2021 30 1) Light Oil Peer Avg. includes: CPG, ERF, RRX, SGY, TOG, TVE, WCP 2) Comparable EV/NTM DACF period subject to Factset broker estimate availability (May 9, 2014 to the close of the acquisition of Spartan Energy Corp. by Vermilion Energy Inc. on May 28, 2018) SPARTAN OIL 268% Total Return and 128% CAGR | June 2011 – January 2013

Overview Relative Performance (Indexed to 100)

250 ▪ Formed through the spin-out of certain Cardium assets and SE Spartan As a public company, Spartan Saskatchewan assets from Spartan Exploration TSX Energy outperformed the TSX Energy Index by ~130% ▪ Spartan continued to consolidate its position in the Pembina 200 Cardium, where it successfully built a large contiguous land position and drilled 80 gross wells with 100% success rate 150 ▪ In less than two years, Spartan Oil grew production per share >500% and cash flow per share >1,000% 100 ▪ Announced its sale to Bonterra in December 2012 at top decile metrics 50 Jun-11 Sep-11 Dec-11 Mar-12 Jun-12 Sep-12 Dec-12

Production Growth Cash Flow Growth

5,000 60.0 $25.0 $0.30 ($/mmsh.) Share Per Flow Cash

4,000 48.0 Share Per Production $20.0 $0.24 (boe/d/mmsh.)

3,000 36.0 $15.0 $0.18

2,000 24.0 $10.0 $0.12 Cash Flow Cash Flow ($mm) Production Production (boe/d) 1,000 12.0 $5.0 $0.06

0 0.0 $0.0 $0.00 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2011 2012 2011 2012

Production Production per Share Cash Flow Cash Flow per Share

March 26, 2021 31 SPARTAN EXPLORATION 573% Total Return and 80% CAGR | January 2010 – May 2011

Overview Relative Performance (Indexed to 100)

250 ▪ Spartan Exploration was formed in Q1-2008 with a view of Spartan targeting tight oil resources plays in western Canada TSX Energy As a public company, Spartan outperformed the 200 ▪ Spartan accumulated Cardium, Bakken and Shaunavon assets TSX Energy Index by ~90% throughout 2008 and 2010 followed by a reverse takeover (RTO) recap transaction of a TSX listed shell company 150

▪ From the RTO transaction in Q1-2010 to its sale in Q1-2011, Spartan grew production from ~400 boe/d to ~2,500 boe/d 100 delivering production per share growth of >425% and cash flow per share growth of >650%

50 Jan-10 Apr-10 Jul-10 Oct-10 Jan-11 Apr-11

Production Growth Cash Flow Growth

3,000 90.0 $14.0 $0.35 ($/mmsh.) Share Per Flow Cash

2,500 75.0 Share Per Production $12.0 $0.30

(boe/d/mmsh.) $10.0 $0.25 2,000 60.0 $8.0 $0.20 1,500 45.0 $6.0 $0.15 1,000 30.0

$4.0 $0.10

Cash Flow ($mm) Production Production (boe/d) 500 15.0 $2.0 $0.05

0 0.0 $0.0 $0.00 Q1 Q2 Q3 Q4 Q1 Q1 Q2 Q3 Q4 Q1 2010 2011 2010 2011

Production Production per Share Cash Flow Cash Flow per Share

March 26, 2021 32 DISCLAIMER

Forward Looking Statements effect on Spartan. While the precise impact of the COVID-19 virus on Spartan remains unknown, ▪ Certain information included in this presentation constitutes forward-looking information under rapid spread of the COVID-19 virus may have a material adverse effect on global economic applicable securities legislation. Forward looking information typically contains statements with activity, and can result in volatility and disruption to global supply chains, operations, mobility of words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", "project" or people and the financial markets, which could affect interest rates, credit ratings, credit risk, similar words suggesting future outcomes or statements regarding an outlook. Forward-looking inflation, business, financial conditions, results of operations and other factors relevant to information in this presentation may include, but is not limited to, statements about: corporate Spartan. Please refer to the Spartan's most recent Annual Information Form and MD&A for strategy, objectives, strengths and focus of Spartan; the intentions of management and Spartan additional risk factors relating to Spartan, which can be accessed either on Spartan's website at with respect to its growth strategy and business plan; Spartan's expectations regarding its www.spartandeltacorp.com or under the Company's profile on www.sedar.com. Readers are 2020/2021 drilling program, including the location of wells, scheduled drilling dates and the timing cautioned not to place undue reliance on this forward-looking information, which is given as of the of expected pay out from such wells; Spartan's intentions to maintain balance sheet flexibility to date hereof, and to not use such forward-looking information for anything other than its intended allow Spartan to take advantage of future opportunities; Spartan's acquisition and consolidation purpose. Spartan undertakes no obligation to update publicly or revise any forward-looking strategy and targets; Spartan plans to deliver strong operational performance and reduce debt; information, whether as a result of new information, future events or otherwise, except as Spartan's production forecasts; Spartan 2021 guidance and budget, including anticipated capital required by law. expenditures and Spartan's ability to fund capital expenditures through operating activities; ▪ The forward-looking information contained in this presentation is made as of the date hereof and Spartan's cost-cutting measures and the results thereof; Spartan's ESG initiative; predictions Spartan undertakes no obligation to update publicly or revise any forward-looking information, regarding commodities pricing and industry fundamentals, including natural gas demand and whether as a result of new information, future events or otherwise, unless required by applicable supply; the continuation of Spartan's strategic partnerships, and expected benefits therefrom. securities laws. The forward looking information contained in this presentation is expressly Statements relating to "reserves" are also deemed to be forward looking statements, as they qualified by this cautionary statement. 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 ▪ FOFI. This presentation contains future-oriented financial information and financial outlook produced in the future. information (collectively, "FOFI") about Spartan's prospective results of operations, production, working capital, capital efficiency, sustaining capital, capital expenditures, enterprise value, ▪ The forward-looking statements contained in this presentation are based on certain key recycle ratio, payout, operating netback, share price, investment yield, net debt (surplus), expectations and assumptions made by Spartan, including expectations and assumptions adjusted free funds flow, free funds flow, NPV10, NOI, IRR, return of capital, operating costs, concerning the performance of Spartan's management team and board, the success of future cost reductions and components thereof, all of which are subject to the same assumptions, risk drilling, development and completion activities, the performance of existing wells, the factors, limitations and qualifications as set forth in the above paragraphs. FOFI contained in this performance of new wells, the availability and performance of facilities and pipelines, the presentation was approved by management of the date of this presentation and was provided for geological characteristics of Spartan's properties, the successful application of drilling, completion the purpose of providing further information about Spartan's anticipated future business and seismic technology, prevailing weather and break-up conditions and access to drilling operations. Spartan disclaims any intention or obligation to update or revise any FOFI contained locations, commodity prices, price volatility, price differentials and the actual prices received for in this presentation, whether as a result of new information, future events or otherwise, unless products, royalty regimes and exchange rates, the application of regulatory and licensing required pursuant to applicable law. Readers are cautioned that the FOFI contained in this requirements, the availability of capital, labour and services, Spartan's ability to complete planned presentation should not be used for purposes other than for which it is disclosed herein. capital expenditures within budgeted cost estimates, the ability to market oil and gas successfully, Spartan's ability to integrate assets and employees acquired through acquisitions and the ▪ Third Party Information. Certain information contained herein has been obtained from published creditworthiness of industry partners. sources prepared by independent industry analysts and third-party sources (including industry publications, surveys and forecasts). While such information is believed to be reliable for the ▪ Although Spartan believes that the expectations and assumptions on which the forward-looking purpose used herein, none of the directors, officers, owners, managers, partners, consultants, statements are based are reasonable, undue reliance should not be placed on the forward- shareholders, employees, affiliates or representatives assumes any responsibility for the looking statements because Spartan can give no assurance that they will prove to be correct. accuracy of such information. Some of the sources cited in this presentation have not consented Since forward-looking statements address future events and conditions, by their very nature they to the inclusion of any data from their reports, nor has Spartan sought their consent. 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, stock market volatility, 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 complete or realize the benefits of acquisitions, constraint in the availability of services, commodity price and exchange rate fluctuations, actions of OPEC and OPEC+ members, 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. In addition, Spartan cautions that current global uncertainty with respect to the spread of the COVID-19 virus and its effect on the broader global economy may have a significant negative

March 26, 2021 33 DISCLAIMER CONT’D

Oil and Gas Advisories ▪ BOE Disclosure. The term barrels of oil equivalent ("boe") may be misleading, particularly if used ▪ "Undeveloped F&D costs" are calculated as the sum of development capital, divided by the in isolation. A BOE conversion ratio of six thousand cubic feet of natural gas to barrels of oil undeveloped reserves at the proved undeveloped and proved plus probable undeveloped levels. equivalence is based on an energy equivalency conversion method primarily applicable at the ▪ "Operating netback" see "Reader Advisories – Non-GAAP Measures". burner tip and does not represent a value equivalency at the wellhead. All BOE conversions in this presentation are derived from converting gas to oil in the ratio mix of six thousand cubic feet ▪ "Recycle ratio" is measured by dividing operating netback by F&D cost per boe for the year. of gas to one barrel of oil. ▪ "Payout" is achieved when revenues, less royalties, production and transportation costs are ▪ Product Types. Throughout this presentation, "crude oil" or "oil" refers to light and medium crude equal to the total capital costs associated with drilling, completing, equipping and tying in a well. oil product types as defined by NI 51-101. Condensate is a natural gas liquid as defined by Management considers payout an important measure to evaluate its operational performance and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). capital allocation processes. It demonstrates the return of cash flow and allows Spartan to References to "natural gas liquids" or "NGLs" throughout this presentation comprise pentane, understand how a capital program is funded under different operating scenarios, which helps butane, propane, and ethane, being all NGLs as defined by NI 51-101 other than condensate, assess Spartan's ability to generate value. which is disclosed separately because the value equivalency of condensate is more closely ▪ "Finding and development (F&D) cost" is the sum of capital expenditures incurred in the period aligned with crude oil. References to "natural gas" or "gas" relates to conventional natural gas. and the change in future development capital ("FDC") required to develop reserves. F&D cost per ▪ Reserves Disclosure. All reserves information in this presentation was prepared by McDaniel & BOE is determined by dividing current period net reserve additions into the corresponding Associates Consultants Ltd. ("McDaniel") effective December 31, 2020 (the "McDaniel Report") period's F&D cost. Readers are cautioned that the aggregate of capital expenditures incurred in using average forecast pricing of McDaniel, GLJ Ltd. ("GLJ") and Sproule Associates Limited the year, comprised of exploration and development costs and acquisition costs, and the change ("Sproule") in accordance with NI 51-101 and the Canadian Oil and Gas Evaluation Handbook in estimated FDC generally will not reflect total FD&A costs related to reserves additions in the (the "COGE Handbook"). Reserves information in relation to the Acquisitions was prepared by: year. (a) Sproule effective December 31, 2019, regarding the Inception assets; and (b) GLJ effective ▪ "IP30" is the initial production from a well for the first 720 hours (30 days) based on October 1, 2020, regarding the Simonette assets, in accordance with NI 51-101 and the COGE operating/producing hours. Handbook. The estimates of reserves in this presentation do not include reserves attributed to the newly acquired Willesden Green assets. The estimates of reserves and future net revenue for the ▪ "IP60" is the initial production from a well for the first 1,440 hours (60 days) based on assets to be acquired pursuant to the Acquisitions may not reflect the same confidence level as operating/producing hours. estimates of reserves and future net revenue for all of Spartan's properties, due to the effects of ▪ "NPV10" is the anticipated net present value of the future net operating income after capital aggregation. While the above referenced reserves reports use different forecasted pricing and expenditures, discounted at a rate of 10% (before tax). cost assumptions as of their respective effective dates, Spartan has performed sensitivity ▪ Type Curves. The reservoir engineering and statistical analysis methods utilized is broad and can analysis on such assumptions and has determined that variances in reserves values due to the include various methods of technical decline analyses, and reservoir simulation all of which are different effective dates do not lead to materially misleading results when reserves are disclosed generally prescribed and accepted by the COGE Handbook and widely accepted reservoir on a pro-forma basis. Given the foregoing, management believes that pro-forma estimates of engineering practices. These type curves were generated by McDaniel, an independent qualified reserves disclosed herein are not misleading with respect to assumptions, input data and the reserves evaluator. These type curves incorporate the most recent data from actual well results professional judgment of the qualified reserves evaluators. All reserve references in this and would only be representative of the specific drilled locations. There is no guarantee that presentation are "Company share reserves". Company share reserves are the applicable Spartan will achieve the estimated or similar results derived therefrom. company's total working interest reserves before the deduction of any royalties and including any royalty interests payable to the company. It should not be assumed that the present worth of ▪ Drilling Locations / Inventory. This presentation discloses drilling inventory in three categories: (i) estimated future amounts presented in the tables above represents the fair market value of the proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and reserves. There is no assurance that the forecast prices and costs assumptions will be attained, probable locations are derived from the McDaniel Report and account for drilling locations that and variances could be material. The recovery and reserve estimates of the crude oil, natural gas have associated proved and/or probable reserves, as applicable. Unbooked locations are internal liquids and natural gas reserves provided herein are estimates only and there is no guarantee estimates based on our prospective acreage and an assumption as to the number of wells that that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids can be drilled per section based on industry practice and internal review. Unbooked locations do reserves may be greater than or less than the estimates provided herein. All evaluations and not have attributed reserves or resources. Of the 864 (590 net) total drilling locations identified summaries of future net revenue are stated prior to the provision for interest, debt service herein, 75 (63 net) are proved locations, 43 (38 net) are probable locations and 746 (489 net) are charges or general and administrative expenses and after deduction of royalties, operating costs, unbooked locations. Of the 118 (101 net) FDC drilling locations identified herein, 75 (63 net) are estimated well abandonment and reclamation costs and estimate future capital expenditures. proved locations, and 43 (38 net) are probable locations. Unbooked locations have been identified by management as an estimation of our multi-year drilling activities based on evaluation ▪ Oil and Gas Metrics. This presentation contains metrics commonly used in the oil and natural gas of applicable geologic, seismic, engineering, production and reserves information. There is no industry which have been prepared by management, such as "development capital", "F&D costs", certainty that we will drill all unbooked drilling locations and if drilled there is no certainty that such "operating netback", "recycle ratio", "payout", "F&D costs", "IP90" and "NPV10". These terms do locations will result in additional oil and gas reserves, resources or production. The drilling not have a standardized meaning and may not be comparable to similar measures presented by locations on which we drill wells will ultimately depend upon the availability of capital, regulatory other companies, and therefore should not be used to make such comparisons. Management approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional uses these oil and gas metrics for its own performance measurements and to provide reservoir information that is obtained and other factors. While certain of the unbooked drilling shareholders with measures to compare our operations over time. Readers are cautioned that the locations have been de-risked by drilling existing wells in relative close proximity to such information provided by these metrics, or that can be derived from the metrics presented in this unbooked drilling locations, other unbooked drilling locations are farther away from existing wells presentation, should not be relied upon for investment or other purposes. where management has less information about the characteristics of the reservoir and therefore ▪ "Development capital" means the aggregate exploration and development costs incurred in the there is more uncertainty whether wells will be drilled in such locations and if drilled there is more financial year on reserves that are categorized as development. Development capital excludes uncertainty that such wells will result in additional oil and gas reserves, resources or production. capitalized administration costs.

March 26, 2021 34 DISCLAIMER CONT’D

Non-GAAP Measures ▪ This presentation contains certain financial measures, as described below, which do not have ▪ "Enterprise value" is calculated as the Market Capitalization of the Company plus Net Debt, standardized meanings prescribed by IFRS or Generally Accepted Accounting Principles where "Market Capitalization" is defined as the total number of common shares outstanding ("GAAP"). As these non-GAAP financial measures are commonly used in the oil and gas multiplied by the price per share at a given point in time. industry, the Company believes that their inclusion is useful to investors. The reader is cautioned that these amounts may not be directly comparable to measures for other companies where ▪ "EV/DACF" is the enterprise value divided by the debt adjusted cash flow and is used as a similar terminology is used. The non-GAAP measures used in this presentation, represented by measurement of the value of the company. the capitalized and defined terms outlined below, are used by Spartan as key measures of financial performance and are not intended to represent operating profits nor should they be ▪ "Sustaining / maintenance capital" is the estimated capital required to bring on new production viewed as an alternative to cash provided by operating activities, net income or other measures of which offsets the natural decline of the existing production and keeps the year-over-year financial performance calculated in accordance with IFRS. production flat. ▪ "Operating Income (Loss)" abbreviated as "NOI" is calculated by deducting operating and ▪ "Capital efficiency" is the amount spent to add an additional barrel a day of production to a transportation expenses from total revenue, after realized gains or losses on commodity price company's annual exit production. derivative financial instruments. Total revenue is comprised of oil and gas sales, net of royalties, plus processing and other revenue. The Company refers to Operating Income (Loss) expressed ▪ "Internal rate of return (IRR)" is the discount rate required to arrive at an NPV equal to zero. per unit of production as an "Operating Netback". "Run Rate NOI" is calculated based on Rates of return set forth in this presentation are for illustrative purposes. There is no guarantee annualized production and Operating Netback figures. Where a non-IFRS or IFRS measure in that such rates of return will be achieved in the future. this presentation is qualified by the words "run rate", it represents the "pro forma" figure as adjusted to give effect to the Acquisitions. Spartan considers Run Rate NOI as an important ▪ “Payout Ratio” is the ratio derived from total capital expenditures net of acquisitions and measure to illustrate how the Corporation would have performed if the Acquisitions had been divestitures divided by Adjusted Funds Flow consummated at the start of the period. ▪ US Disclaimer. This presentation is not an offer of the securities for sale in the United States. ▪ "Funds from Operations" is calculated as cash provided by (used in) operating activities before The securities have not been registered under the U.S. Securities Act of 1933, as amended, and changes in non-cash working capital. may not be offered or sold in the United States absent registration or an exemption from registration. This presentation shall not constitute an offer to sell or the solicitation of an offer to ▪ "Adjusted Funds from Operations" is calculated by adding back transaction costs on buy nor shall there be any sale of the securities in any state in which such offer, solicitation or acquisitions and settlements of decommissioning obligations to Funds from Operations. Adjusted sale would be unlawful. Funds from Operations can also be calculated by deducting general and administrative and interest expenses (net of interest income) from Operating Income (Loss). Spartan's "Corporate Netback" is equal to Adjusted Funds from Operations expressed per unit of production. ▪ "Adjusted Funds from Operations per Share" is calculated on a consistent basis with net income (loss) per share, using basic and diluted weighted average common shares as determined in accordance with IFRS. ▪ "Adjusted Funds Flow" is calculated by deducting settlements of decommissioning obligations and lease payments from Adjusted Funds from Operations. The Company believes Adjusted Funds Flow is an appropriate metric to compare relative to Net Debt because it reflects the net cash flow generated from routine business operations and because Spartan does not include lease liabilities in its definition of Net Debt (Surplus). ▪ "Free Funds Flow (FCF)" is calculated as Adjusted Funds Flow less total net capital expenditures, excluding acquisitions. Spartan believes Free Funds Flow provides an indication to investors and Spartan shareholders of the amount of funds the Company has available for future capital allocation decisions. ▪ "Net Debt (Surplus)" includes bank debt, net of Adjusted Working Capital. "Adjusted Working Capital" is calculated as current assets less current liabilities, excluding derivative financial instrument assets and liabilities and lease liabilities. As at December 31, 2020 and 2019, the Adjusted Working Capital deficit (surplus) includes cash and cash equivalents, accounts receivable, prepaid expenses and deposits, accounts payable and accrued liabilities and the current portion of decommissioning obligations. Spartan uses Net Debt (Surplus) as a measure of the Company's financial position and liquidity, however it is not intended to be viewed as an alternative to other measures calculated in accordance with IFRS.

March 26, 2021 35 PRICE DECK DETAILS Spartan Budget Pricing

All guidance, forecasts and economics are based on the following budget price deck (unless otherwise stated):

March 26, 2021 36 ABBREVIATIONS

AECO Alberta Energy Company “C” Meter Station of the NOVA Pipeline System ARO Asset Retirement Obligations b Basic shares outstanding bbl; bbl/d barrel; barrels per day bcf; bcf/d Billion cubic feet of natural gas; billion cubic feet per day of natural gas boe; boe/d Barrels of oil equivalent; barrels of oil equivalent per day BXE Bellatrix Exploration Ltd. CCAA Companies' Creditors Arrangement Act (Canada) cf/d cubic feet per day of natural gas CO&O Construction, Ownership, and Operating Agreement DCET Drill, complete, equip and tie-in capital cost ESG Environmental, Social and Governance EUR Estimated ultimate recovery (see disclaimers) EV/DACF Enterprise value divided by the debt adjusted cash flow (see disclaimers) F&D Finding and development cost per barrel of oil equivalent (see disclaimers) f.d. Fully diluted shares outstanding FCF Free Cash Flow (see disclaimers) FX Exchange rate: US Dollars divided by Canadian Dollars G&A General and administrative expense GJ Gigajoules IFRS International Financial Reporting Standards as issued by the International Accounting Standards Board (“IASB’) IOGC Indian Oil and Gas Canada IP90 The average hydrocarbon production rate for the first 90 days of a well's life IRR Internal rate of return percentage (see disclaimers) LMR Liability Management Rating (Alberta) M or m Thousand MM or mm Million NGLs Natural Gas Liquids NOI Net Operating Income (see disclaimers) NPV10 Net Present Value with a discount rate of 10% (see disclaimers) PBUD Probable Undeveloped PDP Proved Developed Producing Reserves PUD Proven Undeveloped SDE Trading symbol for Spartan Delta Corp. common shares on the TSX Venture Exchange tCO2e Tonnes (t) of carbon dioxide (CO2) equivalent €

March 26, 2021 37 [email protected] www.SpartanDeltaCorp.com