Slides
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INVESTOR DAY PRESENTATION MAY 14, 2025
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Agenda 2
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(1) Based on 235.5 million common shares and the closing share price on the TSX of $23.12 on May 7, 2025 andnet debt of $258.8 million at March 31, 2025. (2) Trailing 12-months. See Non-GAAP Measures and Ratios. (3) Financial data in this corporate presentation is as at March 31, 2025 unless stated otherwise. PrairieSky Royalty Snapshot 18.5 Million Acres of Royalty Lands Canada’s Largest Portfolio of Fee Simple Mineral Title $2.2 Billion Returned to Shareholders since IPO Oil & Liquids 93% of Q1 2025 Royalty Production Revenue Sustainable Annual Dividend $1.04 Per Common Share Paid Quarterly Balance Sheet Strength 0.5x D/EBITDA(2) TSX PSK $5.7 Billion Enterprise Value(1) 6% Growth In Royalty Oil Production, 2024 3
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Why PrairieSky? Vast Land Base Experienced Team Resource Play Upside Diversification Optionality Sustainability Growth + Yield • 9.8 million acres of Fee Lands • 8.7 million acres of GORR Lands • Management and directors with an unparalleled understanding of the royalty business and are invested alongside shareholders • Upside from resource play development on emerging plays including the Duvernay,Clearwater and multi-zonal Mannville Stack plays • Approximately 340 lessees producing from over 30 geologic horizons • Exposure to both oil and natural gas prices • Technology, new pool discoveries, optimization of legacy production and secondary and tertiary recoveries all provide long-term option value • Fee Simple land never expires • Conservative dividend payout ratio, 71% in Q1/25 • No maintenance capital expenditures, operating costs, abandonment or environmental liabilities = low sensitivity to inflation • Strong balance sheet, 0.5x D/EBITDA (trailing 12-months) • Tradingat attractive FCF yield, with momentum in oil royalty production volumes, including 2024 organic growth of 6% per share 4
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PrairieSky’s Dominant Land Position PrairieSky has more than tripled its Royalty Lands since inception, a 96% increase on a per share basis(1), including the addition of: • All Saskatchewan Fee Lands and GORR acreage • 1.4 million Clearwater acres • Mannville Stack position through acquisition from Heritage Royalty in December 2021 5.2 million acres in Alberta on IPO (2014) 18.5 million acres across Western Canada today (1) Using common shares outstanding at IPO and at March 31, 2025. 5
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PrairieSky Key Growth Metrics (1) Using weighted average number of common shares in each quarter. (2) Conventional oil and gas reinvestment estimates from ARC energy research institute Oil Royalty Production CAGR of 6% per share since Q1/22 (post Heritage acquisition). Increased share of gross industry capital on PrairieSky’s lands over past 5 years. 0.0% 1.0% 2.0% 3.0% 4.0% 5.0% 6.0% 7.0% 8.0% 9.0% $0.0 $0.5 $1.0 $1.5 $2.0 $2.5 2020 2021 2022 2023 2024 $ billions Share of Industry Capital(2) Gross Capital on PSK Land % of Industry Capital Avg Royalty Rate on New Spuds (%) - 20 40 60 80 100 120 Production per Million Shares(1) Oil NGL Natural Gas (boe) 6
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Oil Production Growth Decoupled from Western Canada Following the acquisition from Heritage Royalty in December 2021, PrairieSky has organically exceeded the growth rate of the Western Canadian Sedimentary Basin on oil volumes through: • Outsized exposure to conventional oil plays at the lowest parts of the cost curve (ie. Clearwater, Mannville Stack) • Leases and royalty agreements with a relatively high proportion of growth oriented private producers • Depth of conventional oil inventory through vast 18.5 million acre royalty position WCSB data from CER (Canada Energy Regulator). *Q1/25 data not yet available for WCSB -10.0% -5.0% 0.0% 5.0% 10.0% 15.0% 20.0% 25.0% Oil Production Growth (from Q1/22 Baseline) PSK WCSB 7
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Returns to Shareholders High conversion of revenues to funds from operations for distribution to shareholders through all commodity price cycles. From IPO to March 31, 2025, PrairieSky has returned $1.9 billion in dividends and $336 million in share buybacks to shareholders (average price of $16.74/share). PrairieSky pays a quarterly dividend of $0.26 per share. Low payout ratio allows for low dilution acquisitions, setting up for funds from operations and dividend growth over the next 10+ years. - 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 IPO (May 29, 2014) - March 31, 2025 $ billions Total Revenue Funds from Operations Returned to Shareholders 8
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Reserves Replacement Share Count (1) Funds from Operations Oil & Liquids (MBBL) Total (MBOE) (mm) (MBOE) % liquids ($ millions) 2016 19,914 47,423 228 8,531 47% $200.2 2017 20,848 49,234 9,221 48% $290.2 2018 21,203 47,482 8,526 49% $229.7 2019 22,355 45,835 7,941 52% $220.4 2020 22,135 48,189 7,215 49% $146.8 2021 32,953 66,250 7,238 50% $273.4 2022 32,963 66,719 9,200 57% $507.6 2023 32,693 65,762 9,072 60% $382.5 2024 33,078 63,653 239 9,218 62% $380.5 Proved + Probable Reserves (2P) Annual Production Third-party capital on PrairieSky lands has historically replaced produced reserves. Reserves steady in 2024, after annual production of 9,218 MBOE in the year. Reserves per share have increased by 28% since 2016, including +58% for oil and liquids. In a royalty business with undeveloped land, all funds from operations can be returned to shareholders. 2024 funds from operations of $380.5 million primarily used for dividends declared of $239.0 million and a 39% net debt reduction to $134.9 million. (1) Shares outstanding at year end. 9
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Optionality Beyond Current Valuation Expansion of productive trends Material new pool discoveries Improvements in drilling and completions technologies: incremental recovery via optimized completions, tighter inter-wells spacing, and additional application of multi-leg horizontal wells Application of new or expansion of existing waterflood schemes Application of new or expansion of existing EOR schemes Current Future Potential Valuation Well-defined productive trends Value primarily assigned to infills and step-out drilling locations Historical average production rate Only major plays given future value No value assigned to future waterflood or enhanced oil recovery schemes Booked Reserves Producing wells as of December 31, 2024 Future Optionality 10
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2025 2017 Playbook Methodology – Expansion of Development Area with Time Booked Reserves Playbook Valuation Future Optionality 11
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Royalty Asset Summary $29.8 billion total undiscounted value WTI US$65.00/bbl AECO $2.50/mcf >34,000 future locations identified in 29 plays (54% on Fee Land) Top 5 plays by value: Central Alberta Mannville Heavy Oil Central Alberta Clearwater Oil Western Saskatchewan Viking Oil Central Alberta Duvernay Central Alberta Viking Oil 4x increase in SE Saskatchewan Mississippian oil future locations – now $1.5 billion in total undiscounted value 12 Region / Play Booked Reserves (MBOE) Undisc. Booked Value ($MM) Future Fee Locations Future GORR Locations Future Potential (MBOE) Undisc. Future Potential ($MM) Total Volume (MBOE) Undisc. Total Value ($MM) Central AB 31,114 $1,480 8,480 7,890 346,158 $16,443 377,272 $17,923 Shallow Gas 2,554 $34 710 280 3,357 $41 5,911 $75 Belly River Oil 396 $27 80 70 2,689 $169 3,085 $196 Cardium Oil 1,058 $39 1,000 800 30,863 $1,213 31,921 $1,252 Viking Oil 1,103 $76 2,290 1,360 33,705 $2,288 34,808 $2,364 Mannville Gas 5,824 $113 1,050 610 94,058 $1,804 99,882 $1,917 Mannville Light Oil 1,151 $51 690 170 31,451 $1,230 32,602 $1,281 Mannville Heavy Oil 7,381 $505 1,540 1,050 55,885 $3,676 63,266 $4,181 Clearwater 5,514 $355 20 3,350 49,876 $3,262 55,390 $3,617 Mississippian Oil 456 $24 70 20 2,876 $139 3,332 $163 Nisku Oil 774 $52 80 0 2,146 $135 2,920 $187 Devonian Oil 455 $33 50 20 871 $65 1,326 $98 Duvernay 1,720 $106 900 160 38,381 $2,421 40,101 $2,527 Other Plays 2,728 $65 0 0 0 $0 2,728 $65 Southern AB 13,991 $407 3,485 680 49,483 $2,451 63,474 $2,858 Shallow Gas 6,043 $90 1,320 260 2,141 $31 8,184 $121 Cardium Oil 492 $28 240 30 5,110 $275 5,602 $303 Mannville Gas 913 $17 630 110 8,993 $166 9,906 $183 Mannville Oil 3,197 $189 1,150 280 29,541 $1,695 32,738 $1,884 Bakken Oil 283 $22 145 0 3,698 $284 3,981 $306 Other Plays 3,063 $61 0 0 0 $0 3,063 $61 NW AB & NE BC 10,764 $250 0 4,440 88,018 $2,256 98,782 $2,506 Cardium Gas 610 $10 0 680 13,459 $259 14,069 $269 Cardium Oil 265 $11 0 290 2,779 $135 3,044 $146 Dunvegan Oil 231 $9 0 240 2,483 $116 2,714 $125 Spirit River Gas 2,711 $41 0 1,050 24,659 $360 27,370 $401 Montney Gas 4,089 $94 0 1,320 29,062 $749 33,151 $843 Montney Oil 630 $23 0 860 15,576 $637 16,206 $660 Other Plays 2,228 $62 0 0 0 $0 2,228 $62 Western Sask 5,272 $328 4,770 2,000 53,178 $3,873 58,450 $4,201 Shallow Gas 621 $7 80 240 390 $5 1,011 $12 Viking Oil 2,707 $196 3,730 1,500 35,216 $2,697 37,923 $2,893 Mannville Oil 1,391 $91 790 260 16,226 $1,084 17,617 $1,175 Bakken Oil 447 $28 170 0 1,346 $87 1,793 $115 Other Plays 106 $6 0 0 0 $0 106 $6 SE Sask & MB 2,512 $191 1,660 660 26,048 $2,091 28,560 $2,282 Bakken Oil 1,210 $92 750 330 7,803 $645 9,013 $737 Mississippian Oil 1,069 $81 910 330 18,245 $1,446 19,314 $1,527 Other Plays 233 $18 0 0 0 $0 233 $18 Total 63,653 $2,656 18,395 15,670 562,885 $27,114 626,538 $29,770
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Highlights of Changes from 2023 Royalty Playbook 13
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Methodology and Summary of Changes Benchmark 2023 2025 WTI ($US/bbl) $70.00 $65.00 AECO ($/Mcf) $3.00 $2.50 Consistent Methodology Model type curves based on well performance in the last 5 years Updated flat pricing: Assigned royalty interest and price offsets using accounting data Defined new play acreage and development acreage for each play as a function of industry activity Counted Fee & GORR locations in each play, assigning well densities, and subtracting wells drilled on PrairieSky land Allocated over 7,700 new industry wells across 31 plays 14 Region / Play Future Fee Locations Future GORR Locations Future Potential (MBOE) Undisc. Future Potential ($MM) Total Volume (MBOE) Total Value Price Sensitivity ($MM) Undisc. Total Value ($MM) Central AB 150 1,070 40,524 $2,013 41,160 -$548 $2,173 Shallow Gas 20 10 -521 -$12 -894 -$18 -$20 Belly River Oil 40 50 1,850 $108 1,945 -$4 $112 Cardium Oil 0 -30 276 -$467 140 -$59 -$478 Viking Oil -260 -110 5,586 $333 5,354 -$44 $315 Mannville Gas 120 110 -9,446 -$573 -10,780 -$203 -$616 Mannville Light Oil 150 20 8,447 $217 8,370 -$56 $207 Mannville Heavy Oil 90 300 7,179 $632 7,286 -$53 $679 Clearwater 0 700 19,519 $1,560 21,313 -$48 $1,710 Mississippian Oil 20 10 1,150 $44 1,175 -$6 $46 Nisku Oil 20 0 -1,001 -$76 -836 -$4 -$69 Devonian Oil 10 0 -92 -$9 -108 -$1 -$10 Duvernay -60 10 7,577 $256 8,567 -$46 $312 Other Plays 0 0 0 $0 -372 -$6 -$15 Southern AB 735 260 5,057 $208 3,697 -$114 $169 Shallow Gas -30 10 -510 -$12 -1,337 -$24 -$36 Cardium Oil 140 20 494 $23 662 -$9 $35 Mannville Gas 410 80 3,038 $24 2,839 -$27 $16 Mannville Oil 210 150 2,362 $162 2,216 -$43 $153 Bakken Oil 5 0 -327 $11 -436 -$3 $6 Other Plays 0 0 0 $0 -247 -$8 -$5 NW AB & NE BC 0 840 4,014 $86 3,247 -$226 $58 Cardium Gas 0 160 7,025 $136 6,982 -$32 $133 Cardium Oil 0 10 555 $1 475 -$4 -$2 Dunvegan Oil 0 10 -381 -$44 -440 -$4 -$47 Spirit River Gas 0 -70 -5,111 -$99 -5,752 -$72 -$115 Montney Gas 0 220 -5,510 -$192 -5,407 -$78 -$199 Montney Oil 0 510 7,436 $284 7,510 -$31 $287 Other Plays 0 0 0 $0 -121 -$5 $1 Western Sask -40 -270 839 -$121 -623 -$55 -$177 Shallow Gas 0 -20 -8 -$1 -559 -$3 -$11 Viking Oil -520 -400 -4,172 -$566 -4,435 -$39 -$593 Mannville Oil 480 160 5,990 $495 5,435 -$12 $479 Bakken Oil 0 -10 -971 -$49 -1,081 -$1 -$53 Other Plays 0 0 0 $0 17 $0 $1 SE Sask & MB 920 350 15,671 $1,247 15,558 -$24 $1,237 Bakken Oil 230 120 704 $55 562 -$8 $45 Mississippian Oil 690 230 14,967 $1,192 15,002 -$16 $1,193 Other Plays 0 0 0 $0 -6 $0 -$1 Total 1,765 2,250 66,105 $3,433 63,039 -$967 $3,460
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Five Feature Plays – Reserve and Upside Value ~45% of PrairieSky’s Future Potential Value in 5 feature plays: Clearwater (12%) Mannville Heavy Oil (14%) Duvernay (9%) Montney Oil & Gas (5%) SAGD (3%) 0 1,000 2,000 3,000 4,000 5,000 0 100 200 300 400 500 600 Future Potential ($MM) Booked Reserves ($MM) Booked Reserves ($MM) vs Future Potential ($MM) SAGD (Onion Lake & Lindbergh) Montney Oil and Gas (AB & BC) Duvernay Oil Clearwater Oil Mannville Heavy Oil (AB & SK) 15
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FEATURE PLAY: CLEARWATER WATERFLOOD ENHANCING SUSTAINABLE GROWTH
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PrairieSky has the largest Clearwater royalty acreage position with ~1,400,000 acres throughout the entire Clearwater trend. Clearwater royalty oil production averaged ~2,000 bbl/d in 2024, delivering 20% growth y/y. The Clearwater is now the largest conventional oil play in Canada. Early entrant (2016/17) enabled acquisition of Clearwater lands in the best parts of the play at the lowest price per acre. Clearwater - Overview 0 500 1,000 1,500 2,000 2,500bbl/d Clearwater Royalty Oil Production 17
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Clearwater – Exploration Upside Significant OOIP and multi-zone inventory upside in exploratory region of Clearwater fairway. Development underway following discoveries at Utikuma, Cadotte, and McLeod Lake. Waterflood pilots initiated at Cadotte and Utikuma. Polymer pilots underway at Utikuma and Muskwa. New exploration concepts to be tested over the next few years, potentially de-risking new development fairways. CADOTTE UTIKUMA MUSKWA MCLEOD LAKE 18
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0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 Jan-22 Jan-23 Jan-24 Jan-25 Net Production bbl/d Waterflood Introduction – Increasing Recovery, Shallowing Declines Secondary recovery of oil through waterflooding has been proven to be an effective way of increasing the recovery rates, shallowing declines, and extending the productive life of conventional oil pools. PrairieSky has an estimated 25% of its royalty oil volumes under secondary recovery, or approximately 3,400 bbl/d, across 120 different oil pools. These volumes contribute to PrairieSky’s low corporate decline rate of ~18% currently, including ~21% on royalty oil production. The Clearwater accounts for ~22% of the secondary recovery oil volumes, which is expected to grow moving forward. PSK Secondary Recovery Oil Volumes over Time 19 24% 22% 10% 7% 7% 6% 24% Secondary Recovery Oil Production Distribution Central AB Mannville Heavy Central AB Clearwater Southern AB Mannville Central AB Nisku Central AB Viking Southern AB Bakken Other Plays *Volumes include oil production under CO2 miscible flood and gas injection EOR schemes
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Clearwater – Waterflood Overview 0 2 4 6 8 10 12 14 16 18 20 0% 5% 10% 15% 20% 25% 30% 35% 40% 2020 2021 2022 2023 2024 2025 Gross Water Injection (Mbbl/d) % Oil Under Waterflood Clearwater reservoir at Nipisi and Marten Hills shows ideal characteristics for secondary recovery application. Recovery factors in the Clearwater anticipated to double from 5% of OOIP on primary development, to 10% under waterflood. First waterflood pilots initiated in 2018, PrairieSky estimates it now has ~33% of Clearwater royalty oil volumes under waterflood support. All development at Nipisi and Marten Hills go forward is expected to utilize waterflood. PSK Waterflood Supported Royalty Oil - Clearwater 20
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Clearwater – Waterflood Patterns At Nipisi, both the Clearwater ‘C’ and ‘B’ reservoirs utilize a lateral ‘line-drive’ waterflood, with stacked injectors where both sands are present. At Marten Hills, the reservoir is significantly thicker, and a stacked ‘bottoms-up’ method is used, where an injector is located in the lower part of the reservoir , with stacked producers in the middle and upper portions of the sand. Nipisi Clearwater Type Log Marten Hills Clearwater Type Log 21
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2024 Royalty Revenue: $58 million Undiscounted Total Value: $3.6 billion Acreage Included in Future Development: 31% Development Locations: 3,370 Including Waterflood: 1,200 ~23 Years of Drilling Inventory Inventory Snapshot – Clearwater 145 187 187 261 229 417 0 50 100 150 200 250 300 350 400 450 500 Average Booked Reserves (2024 Drilling) Playbook Type Curve (Primary Recovery) Playbook Type Curve (Secondary Recovery) Clearwater Type Curve Initial Rate (BOE/d) Ultimate Recovery (MBOE) 22 Play Acreage Incl. in Future Development 2021 Royalty Playbook 1,032 16% 2023 Royalty Playbook 1,354 24% 2025 Royalty Playbook 1,351 31% Total Acreage (thousand acres) Clearwater Locations 2023 Royalty Playbook 2,670 2023-2024 New Drills -292 Incremental Future Locations 992 2025 Royalty Playbook 3,370
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INVESTOR DAY MAY 2025
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In the interest of providing readers with information regarding Spur Petroleum Ltd. (“Spur”), including management's assessment of Spur's future plans and operations, this presentation contains certain forward-looking statements and other information (collectively “forward-looking information”) about Spur's current expectations, estimates and projections. Forward-looking information in this presentation is identified by words such as “anticipate”, “believe”, “expect”, “plan”, “forecast”, “target”, “project”, “could”, “focus”, “vision”, “goal”, “proposed”, “scheduled”, “outlook”, “potential”, “may” , “looking forward to”, or similar expressions and includes suggestions of future outcomes, and include, without limitations, statements with respect to Spur's future focus, plans, operations and strategies, the benefits associated with Spur's asset base, well economics, drilling and development plans and opportunities, drilling costs, capital and operating costs, netbacks, 2021 and 2022 production, capital expenditures, adjusted funds from operations and adjusted working capital guidance, debt reduction plans, targeted debt-to-adjusted-funds flow ratio, decline rates, transportation costs, future dividend plans, free cash flow, recovery factors, drilling inventory, rates of return, payout and infrastructure development plans. Statements relating to reserves and resources are also forward-looking statements, as they involve the implied assessment, based on estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated and can be profitably produced in the future. The forward-looking statements contained in this presentation speak only as of the date of this presentation and are expressly qualified by this cautionary statement. These forward-looking statements are based on assumptions and are subject to numerous risks and uncertainties, certain of which are beyond Spur’s control, including the impact and duration that the COVID pandemic will have on: (i) the demand for oil and natural gas, (ii) our supply chain, and (iii) our ability to produce sell and transport our production. Other risks and uncertainties include the impact of general economic conditions, industry conditions, volatility of commodity prices, currency exchange rate fluctuations, imprecision of reserve and resource estimates, environmental risks, industry capacity, geological, technical, drilling and processing problems and other difficulties in producing reserves, disruptions in the transportation networks on which Spur is reliant, changes in income tax laws, liabilities inherent in oil and natural gas operations, competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel, risks associated with operations, our reliance on key personnel, changes in royalty rates and incentive programs relating to the oil and gas industry, changes in environmental and other regulations, incorrect assessments of the value of acquisitions and the benefits to be derived therefrom, stock market volatility and ability to access sufficient capital. As a result, Spur’s actual results, performance or achievement could differ materially from those expressed, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any events anticipated by the forward-looking statements will transpire or occur. In addition, the reader, is cautioned that historical results are not necessarily indicative of future performance. Spur does not intend, and does not assume any obligation, to update or revise these forward-looking statements, whether as a result of new information, future events or otherwise, except as required by applicable securities laws. Certain information set out herein may be considered as “financial outlook” within the meaning of applicable securities laws. The purpose of this financial outlook is to provide readers with disclosure regarding Spur’s reasonable expectations as to the anticipated results of its proposed business activities for the periods indicated. Readers are cautioned that the financial outlook may not be appropriate for other purposes. ADVISORY REGARDING FORWARD LOOKING STATEMENTS 24
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Barrel of oil equivalent (“boe”) amounts may be misleading, particularly if used in isolation. A boe conversion ratio has been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel. This conversion ratio of six thousand cubic feet of natural gas to one barrel is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Any references in this document to test rates, flow rates, initial and/or final raw test or production rates, early production, and/or "flush“ production rates are useful in confirming the presence of hydrocarbons, however, such rates are not necessarily indicative of long-term performance or of ultimate recovery. Such rates may also include recovered "load" fluids used in well completion stimulation. Readers are cautioned not to place reliance on such rates in calculating the aggregate production for Spur. Such rates may be estimated based on other third-party estimates or limited data available at this time and are not determinative of the rates at which such wells will continue production and decline thereafter. We have included estimated reserves and original oil in place ("OOIP") in this presentation that have been internally estimated by management of Spur. Such estimates have not been prepared in accordance with National Instrument 51-101 ("NI 51-101") and there is no certainty that Spur will ultimately recover such volumes from the wells it drills. OOIP is the equivalent to Total Petroleum Initially In Place ("TPIP"). TPIP, as defined in the Canadian Oil and Gas Evaluation Handbook, is that quantity of petroleum that is estimated to exist in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. A portion of TPIP is considered undiscovered and there is no certainty that any portion of such undiscovered resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of such undiscovered resources. With respect to the portion of TPIP that is considered discovered resources, there is no certainty that it will be commercially viable to produce any portion of such discovered resources. A significant portion of the estimated volumes of TPIP will never be recovered. Estimates of the net present value of the future net revenue from the reserves included in this presentation do not represent the fair market value of such reserves. In this presentation NPV10 represents the net present value of future net reserve discounted at 10%. The estimates of reserves and future net revenue from individual properties or wells may not reflect the same confidence level as estimates of reserves and future net revenue for all properties and wells, due to the effects of aggregation. This presentation contains type curves and well economics. The type curve information presented is based on Spur's historical production. Such type curves and well economics are useful in understanding management's assumptions of well performance in making investment decisions in relation to development drilling and for determining the success of the performance of development wells; however, such type curves and well economics are not necessarily determinative of the production rates and performance of existing and future wells. OTHER ADVISORY REGARDING FORWARD LOOKING STATEMENTS 25
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This presentation contains several metrics commonly used in the oil and natural gas industry, such as "payout" and internal rate of return ("IRR"). These terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this presentation, should not be relied upon for investment or other purposes. In this presentation "payout" is calculated by taking the time, in years, to recover the total costs to drill, complete and equip a well from operating netbacks and "IRR" is calculated as the return on investment, based on production from a well, using management estimated type curves and EURs. "EUR" means estimated ultimate recovery and is calculated as those quantities of petroleum which are estimated, on a given date, to be potentially recoverable from an accumulation, plus those quantities already produced therefrom. This presentation contains the terms “funds flow“, “adjusted funds from operations”, “adjusted working capital”, “free cash flow” and "debt/cash flow" which do not have a standardized meaning prescribed by Canadian generally accepted accounting principles ("GAAP") and therefore may not be comparable with the calculation of similar measures by other companies. Management uses adjusted funds from operations, adjusted working capital, cash flow and debt/cash flow to analyze financial and operating performance. Cash flow and adjusted funds from operations are not intended to represent operating profits nor should they be viewed as an alternative to cash flow provided by operating activities, net earnings or other measures of financial performance calculated in accordance with GAAP. Adjusted funds from operations are calculated as funds flows from operating activities before changes in non-cash working capital. Debt/cash flow represents bank debt, net of adjusted working capital deficiency divided by the adjusted funds from operations. 26 OTHER ADVISORY REGARDING FORWARD LOOKING STATEMENTS
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SPUR OVERVIEW • Spur was founded in 2017 and has been focused on the Clearwater oil play in northern Alberta • We currently hold 1.7 million acres • PrairieSky holds overriding royalty interests on most of the land and virtually all the production • Corporate production is 52,000 boe per day (93% oil) • 30% is under waterflood 27 R24W4 T73 Cadotte 1,200 boe/d McMullen/ McLeod Lake 3,500 boe/d Nipisi 25,000 boe/d Marten Hills 20,000 boe/d Utikuma 1,800 boe/d Slave Lake
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SPUR PERFORMANCE • Spur has grown production at a 50% compounded growth rate since inception, practically all through the drill bit • The company has distributed $855 million to shareholders and has positive adjusted working capital of over $100 million • Total cash raised since inception of $81 million 28MAY 2025 $0 $100 $200 $300 $400 $500 $600 $700 $800 - 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 Spur Production and Adjusted Funds from Operations Annual Production (boe/d) Adjusted FFO ($million)
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WATERFLOOD HISTORY 29 • Provost Veteran Viking C South Unit o Unitized in 1973 o Unit documents show expectations for 5% recovery under primary and 35% under waterflood o The unit operators only did primary development plus select waterflood and produced 2.5 million barrels
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WATERFLOOD HISTORY • Provost Veteran Viking C South Unit o Unitized in 1973 o Unit documents show expectations for 5% recovery under primary and 35% under waterflood o The unit operators only did primary development plus select waterflood and produced 2.5 million barrels • Waterflood was pursued again in 2017 and the pool is now expected to produce 12 MMbbls (5-fold recovery) 30
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WATERFLOOD DESIGN SUCCESS IS HIGHLY DEPENDENT ON RESERVOIR CHARACTERISTICS • The best waterfloods have homogeneous rock, which enables a steady bank of water to push the oil towards the producer well • It should function like a piston 31 Oil Producer (plan view) Water Injector
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WATERFLOOD – THE PAST DECADE MULTI-STAGE FRACKED WELLS • Various operators attempted waterfloods in multi-stage fracked reservoirs, with generally poor results o Alternating fracked wells were converted to water injectors o The problem: hydraulic fractures are not uniform and may communicate with each other o Water will follow the path of least resistance 32 Oil Producer (plan view) Water Injector
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CLEARWATER WATERFLOOD RESERVOIR CHARACTERISTICS • The Clearwater is different from most conventional reservoirs due to its homogenous sand • Predictable, consistent results and low risk of water breakthrough • The graphic shows a core sample from upper Nipisi sand 33
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CLEARWATER WATERFLOOD EVOLVING WELL DESIGNS 34 • Historically, the most common waterflood well design was a line drive, with alternating producer/injector single-leg wells • The “Texas Three Step” design combines a six-leg multilateral and a water injector in the center • The multiple tightly-spaced legs give a strong initial production rate (i.e. quick payout) • Around the same time that the producing legs start to communicate with one another, the water injector’s impact kicks in (i.e. low-decline, stable production and high recoveries)
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- 50 100 150 200 250 300 350 2021 2022 2023 2024 2025 Barrels per day CLEARWATER WATERFLOOD NIPISI 03/2-30-76-6 W5 – IMPACT ON PRODUCTION 35 Water Injection Oil Production This well (a Texas Three Step) has shown a dramatic response to water injection - current production is higher than IP rate, four years later!
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0 50 100 150 200 250Barrels per day CLEARWATER WATERFLOOD NIPISI 03/2-30-76-6 W5 – IMPACT ON RESERVES 36 Oil Production (actual) PDP forecast has increased from 153mbbl on primary to 325mbbl with waterflood PDP Forecast – 2024 PDP Forecast - 2021 Water Injection Started
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THE IMPACT OF WATERFLOOD 37 Well Count Oil Production Well Count Oil Production (bbl/d) • 30% of Spur’s oil production is now under waterflood • Waterflood wells that were on stream as of December 2024 have shown zero decline in five months • Some of these wells have been on production for 4+ years
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NIPISI DOUBLE DOWN WATERFLOOD 38 • Concurrent waterflood development of stacked sands enables us to leverage existing infrastructure to reduce development costs • Expected to double recovery and NPV compared to primary • Double Down NPV per section - $120 million Current waterfloods highlighted in blue 25 km 35 km Nipisi Sand Cabin Creek Sand 0 100 200 300 400 500 600 700Oil Production (bbls/d) Nipisi Half-Section Waterflood Pilot (3 Nipisi Producers and 3 Cabin Creek Producers)
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MARTEN HILLS STACKED WATERFLOOD 39 • Marten Hills is very thick; wells are drilled in a three stacked layers • Injection is into a multilateral well drilled in the lower third of the reservoir; the lower producer (i.e. middle layer) sees the initial benefit of the flood • Eventually, when the lower producer eventually waters out, it will be converted to an injector to support the upper producer - 200 400 600 800 1,000 1,200 1,400 1,600 1 7 13 19 25 31 37 Oil Production (bbl/d) Month Marten Hills Waterflood Response Current production Began injection Expected primary decline 30m Triple Stack Waterflood Waterflooded wells are now producing >3x average of offsetting wells
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SUMMARY 40 • Waterflood will continue to have a huge impact on the value of the Clearwater play • Spur’s corporate decline rate is below 20% and we hope to get it to 15% over the next few years • This would rival SAGD companies’ decline rates, but with our far better capital efficiencies and higher netbacks • PrairieSky paid for primary production (which has exceeded early expectations) and will also get the benefit of waterfloods – without spending any additional capital
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FEATURE PLAY: MANNVILLE STACK TECHNOLOGY UNLOCKING MASSIVE RESOURCE
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PrairieSky defines the Mannville Stack as a conventional heavy oil play (non-thermal) in nine formations of the Mannville Group, located within the area bounded by 51-23W3 and 66-10W4, in the broader Cold Lake Oil Sands region. This is a subset of PrairieSky’s Central Alberta Mannville Heavy Oil grouping in the 2025 Royalty Playbook. The Mannville Stack represents an immense heavy oil resource across a broad area, where industry activity focused on multilateral development is elevated. Mannville Stack – Overview 42
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Mannville Stack – Production Trends 0 40,000 80,000 120,000 160,000 200,000Oil Production (bbl/d) Historical Production by Well Type Vertical Horizontal Multilateral - 200 400 600 800 1,000bbl/d PSK Mannville Stack Royalty Oil Production Conventional heavy oil production, primarily from vertical wells, in the heavy oil belt peaked in 2014/15 at close to 350,000 bbl/d, followed by a steady decline in the 6 years following. Within the Mannville Stack subset area, peak volumes were ~175,000 bbl/d as shown in the graph below. The application of open hole multilateral drilling technology unlocked a multi-zone bypassed resource, converting uneconomic vertical locations into wells with <1-yr payback periods. Starting in 2022, the Mannville Stack has seen a resurgence in production growth driven by multilaterals. PrairieSky’s Mannville Stack royalty volumes averaged ~800 bbl/d in 2024, representing 70% growth y/y. 43
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Mannville Stack – Growing Exposure Post CNQ acquisition (2015) 2023 2025 The Mannville Stack became a core growth asset for PrairieSky following an acquisition from Heritage Royalty in December 2021, which added significant Fee Land in the Lindbergh/Elk Point region PrairieSky continues to augment its exposure in the Mannville Stack through GORR acquisitions on Crown land with oil sands tenure (15-year primary term lease agreements), including ~115,000 acres added since 2023. 44
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Stacked Pay Example – La Corey 24.5 section block of Mannville oilsands rights at La Corey. PSK 10% GORR. 15 MMbbl produced from 313 vertical wells since 1997. Vertical targets were the cleanest, highest quality sandstone reservoirs. Other formations were recognized as heavy oil bearing, but sands have higher clay content and considered sub-commercial with vertical development. Mapping has identified 100 multilateral locations of unexploited heavy oil resource within the Waseca, Sparky A, and Sparky B, which have been de-risked by offsetting drilling. Future upside in the Rex and Clearwater formations, which show thick pay across a wide area, but with higher oil viscosities. 2025 Royalty Playbook methodology only attributes 19 locations. 18 recent multilateral well licenses (Sparky A, Waseca). 45
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Inventory Snapshot – Central Alberta Mannville Heavy Oil 706 1,137 962 335 0 200 400 600 800 1,000 1,200 1,400 2021 2023 2025 Thousand Acres Mannville Heavy Oil Play Acreage Mannville Heavy Mannville Stack 2024 Royalty Revenue: $108 million Undiscounted Total Value: $4.2 billion Development Locations: 2,590 Including Mannville Stack: 747 Over 30 Years of Drilling Inventory *Mannville Stack introduced as a subset starting with the 2025 Royalty Playbook. 46 % Developed Acreage 2021 Royalty Playbook 50% 2023 Royalty Playbook 59% 2025 Royalty Playbook 63% 1,137 2,200 1,297 (335 Mannville Stack) 2,590 (747 Mannville Stack) Total Acreage & Locations Play Acreage (Thousand Acres) Locations 706 980
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PrairieSky Royalty Ltd. Investor Day May 2025
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Caltex Trilogy is a Fast-Growing Private E&P Team’s 4th Privateco and 3rd Iteration of Caltex A trilogy is a set of three works of art that are connected and can be seen either as a single work or as three individual works May 202548 Operations started 2 ½ years ago
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Thank you PrairieSky! 78 Wells drilled by Caltex with PSK as a stakeholder 95k Net acres with Caltex/PSK partnership PrairieSky has been a great partner to the Caltex team since PSK started up in 2014
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~12,300 Boepd in April May 2025 Caltex Trilogy Snapshot A Fast-Growing Private E&P Co. Focused on the Mannville Stack 50 $85MM Equity Raised ~$205MM Est. Operating Income 2025 1.6MM Meters Drilled 10 187% Prod Growth ‘24 168% 2P Reserves Growth 274 Locs 2P Reserve Report >900 Wells In Inventory ~214 Net Sections Zones Tested Off to a great start so far, and lots of running room to go with multi-zonal pay.
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May 2025 What is Caltex Doing? Multi-Lateral Drilling in the Multiple Zones in the Mannville Stack 51 Multiple-well pads at surface to limit footprint and improve cost efficiencies Drill vertically to target reservoir Drill laterally multiple times from the same vertical to maximize reservoir contact with the wellbore Separate, stacked reservoirs developed with individual wells resulting in high well density per section
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A Series of Mannville-Aged Sands: • Separate Oil-charged sands saturated with lower-viscosity heavy oil in our fairway • Mostly non-commercial historically • Minimal water saturations with high reserve density • 300-500M TVD • 2-5 zones charged throughout most of Caltex lands • 3-8m net pay/zn • Logs, core, vertical completions, etc. de-risk the mapping At 4-7 Wells/Section Stacked Zones Add Up: • 2 zones: 8-14 wells per section • 3 zones: 12-21 wells per section • 4 zones: 16-28 wells per section…etc. May 202552 What is the Mannville Stack? A Caltex Example A stack like this has >75MMbo developable OOIP per section!! Other Attributes of the Play • Quick Payouts • Repeatable opportunities, so we can constantly improve costs and technology
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• Consolidated/Perm? • Fishbone/Lined/Multi? Slot Sizes? • Circ String? • Oil quality? • API?/Viscosity?/Circ String?/EOR? Sand?/Liner? • Mud properties? • Hole cleaning/centrifuges • KCL/Amine/OBM? • Clays? Swelling? • OBM/KCL/Amine? • Wellbore Geometry? • Diameter/Lateral length/wellbore geometry/# of legs? Spacing/Lined? • Surface Challenges? • Access?/VRU?/Fan style?/fuel gas? May 202553 “The Stack” As you Know This Business is Hard…
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C$75.00/bbl WCS May 202554 The Profitability of the Stack 100% Oil + Low costs = Strong Netbacks! • Strong per well rates • Low water-cuts • Clean oil at all leases allows for mktg flexibility • Pad drilling • High reserve density 0 50 100 150 200 250 0 12 24 36 48 60 72 Oil Rate (bbl/d) Month Caltex Median Well - Payouts vs Rate C$75 WCS 1 2 3 4 OPEX ADVANTAGES HIGH NETBACKS CAPEX ADVANTAGES & MODERATE DECLINES STRONG RECYCLING OF CASH • No fracs • Minimal infra needs • Consume own gas • Gas/SWD Infra $47.49 $12.96 $5.85 $5.70 $3.00 $0 $10 $20 $30 $40 $50 $60 Q4/24 Op. Netback per BOE (Excl. Hedging) (Source: Peters & Co. (2025-03) and Company Reports) Operating Netback Royalties Operating Costs Transportation Blend/Quality Heavy Oil Weighted Light Oil Weighted > 40% Gas Median well pays out 3 times in 4.5 years at C$75 WCS ($1.8 million DCE)
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May 202555 The Power of the Stack One section of land producing >1,500 BOPD from ~400m depth 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000BOEPD Ft Kent Sec 7-62-04W4 LSPK USPK WSEC Multi-Zones Compound the Profitability • 3 zones tested and developed in the last 2 years on this section • $20.1mm invested* (Full cycle) • $27.7mm Op Income to date* • Fully paid out • Current run-rate of ~$30MM/yr • Remaining inventory to drill *Thru March 31, 2025 This is one of Caltex’ ~214 sections of land
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May 202556 The Power of the Stack Currently Three Anchor Zones with Multiple other Growth Opportunities Growth TO DATE • Caltex has now rig-released 135 horizontal wells • We have 3 anchor zones producing the lion’s share of corp production with significant inventory remaining to continue growth • We have now tested 10 zones, with significant opportunity for growth in these other zones • 7 of the 10 zones Caltex has tested have had IP’s >100 bopd so far, with 5 having IP’s >150 bopd • We continue to advance techniques and technology to improve type curves on different zones and in different areas 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 2022-10-01 2022-11-01 2022-12-01 2023-01-01 2023-02-01 2023-03-01 2023-04-01 2023-05-01 2023-06-01 2023-07-01 2023-08-01 2023-09-01 2023-10-01 2023-11-01 2023-12-01 2024-01-01 2024-02-01 2024-03-01 2024-04-01 2024-05-01 2024-06-01 2024-07-01 2024-08-01 2024-09-01 2024-10-01 2024-11-01 2024-12-01 2025-01-01 2025-02-01 2025-03-01 2025-04-01 BOEPD Net Corp Prod by Zone WSEC LSPK USPK CMGS MCL SPKB Other
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0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 9/1/2022 12/1/2022 3/1/2023 6/1/2023 9/1/2023 12/1/2023 3/1/2024 6/1/2024 9/1/2024 12/1/2024 3/1/2025 6/1/2025 9/1/2025 12/1/202 New Plays/Zones Drive Growth 10 Zones Tested to Date May 202557 BOEPD 1st PSK GORR Sale (Sept 2023) 1st PSK Lease Agreement 2 Well Commitment (Sept 2022) Fort Kent Lower Sparky Tested Lindbergh/Reita Acquisition Charlotte Lake Upper Sparky & Fort Kent Waseca Recently Testing New Opportunities 47th well drilled on original PSK agreement (Nov 2024) Have now executed 16 deals with PSK 2H25 & Future Upcoming Tests Fort Kent Upper Sparky Tested/Lindbergh Acquisition Fort Kent Acquisition Lindbergh Waseca First wells drilled
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• Busy capital program for 2H’25 that will efficiently grow volumes and test new opportunities May 202558 Outlook • The team will continue to look to grow lands thru farm-in, landsales, and acquisitions • Will continue to be opportunistic for other acquisition opportunities that fit the team’s skillsets
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May 2025 Legal Disclaimer 59 FORWARD-LOOKING STATEMENTS This presentation (“Presentation”) of Caltex Trilogy Ltd. (the “Corporation”) contains certain forward-looking statements or forward-looking information (including future-oriented financial information or financial outlooks) under applicable securities laws. Such forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", “budget”, "plan", "intend", "estimate", “forecast”, "propose", “may”, “could”, or similar words and phrases suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this Presentation may include, but are not limited to statements and information regarding: the Corporation’s capital program and operations, business strategies and objectives, operational and financial performance, statements with respect to future events or future performance, management’s expectations regarding the Corporation’s growth and realization of projected future value, projected operating income, productivity and reserves growth, well inventory, well rates, comparative results of third parties’ exploration and production operations, the value created from technology transfer, reserve density, repeatable opportunities, improvements to costs and technology, cost and netback expectations, payout timelines, expectations of future funds from operations and free cash flow, expectations of future returns, estimated future revenues, future requirements for additional capital and the reserves and resource estimates including OOIP, number of wells per section, production estimates, costs and revenue, business prospects and opportunities, projected land production, remaining drill inventory, zone production value and growth opportunities, number and production of rigs, oil quality, water-cuts, pricing, volume growth, drilling and development plans and opportunities, projected land growth and methods, cashflow, and drilling inventory. In addition, statements (including data in tables) relating to reserves and resources, including OOIP, are forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, and no assurance can be given that the estimates and assumptions are accurate and that such reserves and resources will be realized. By their nature, forward-looking statements and information are subject to numerous risks & uncertainties, some of which are beyond the Corporation’s control, including the impact of general economic conditions, industry conditions, volatility of commodity prices and the effects thereof, imprecision of reserves estimates, changes in exchange rates, and significant declines in production or sales volumes due to unforeseen circumstances, the effect of possible changes in critical accounting estimates, exploration and development plans and the timing thereof, the potential financial and operational impact of environmental, social and governance-related risks (ESG), including climate risks, and regulatory actions taken in respect thereof, competition from other industry participants, the lack of qualified personnel or management, the ability to access sufficient capital from internal and external sources, acquisition and disposition plans and the timing thereof, operating and other expenses, including the payment and amount of future dividends, royalty and income tax rates and the Corporation’s expectations regarding future taxes and taxability, treatment under governmental regulatory regimes, the timing of regulatory proceedings and approvals, and excessive cost escalation as well as development, permitting, infrastructure, operating or technical difficulties on any of the properties in which the Corporation operates. Although the Corporation believes that the expectations reflected in such forward-looking statements or information are reasonable based on information currently available to it, undue reliance should not be placed on forward-looking statements or information as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both generally and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur. Although the Corporation believes that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct and, accordingly that actual results will be consistent with the forward-looking statements. The forward-looking statements or information contained in this document are made as of the date hereof and the Corporation undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws. The forward looking statements and information contained herein, and any subsequent forward looking statements or information, written or oral, attributable to the Corporation or persons acting on its behalf, are expressly qualified by this advisory and disclaimer. Reserves estimates have been made assuming that development of each property in respect of which the estimate is made will occur, without regard to the likely availability of funding required for such development. The actual crude oil and natural gas reserves and future production will be greater than or less than the estimates provided in this Presentation. Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (BOE) may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. Financial data contained within this Presentation are reported in Canadian dollars unless otherwise stated. UNDER NO CIRCUMSTANCES WHATSOEVER SHALL THE CORPORATION, ITS DIRECTORS, OFFICERS, REPRESENTATIVES, AGENTS, CONSULTANTS OR EMPLOYEES BE LIABLE FOR ANY DIRECT, INDIRECT OR CONSEQUENTIAL LOSS OR DAMAGE SUFFERED BY ANY PERSON RELYING ON ANY STATEMENTS OR OMISSIONS FROM THIS PRESENTATION AND TO THE MAXIMUM EXTENT PERMITTED BY LAW, ALL CONDITIONS, WARRANTIES AND OTHER TERMS WHICH MIGHT BE IMPLIED BY STATUTE, COMMON LAW OR THE LAW OF EQUITY ARE EXPRESSLY EXCLUDED.
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CAUTIONARY STATEMENT FOR US INVESTORS This Presentation does not constitute or form part of, and should not be construed as, an offer to sell or the solicitation of an offer to purchase or subscribe for any securities. Any securities of the Corporation to be offered or sold will be offered on a “private placement” basis solely to accredited investors, as defined Rule 501 of Regulation D under the United States Securities Act of 1933, as amended (the “Securities Act”). If an offer to sell or the solicitation of an offer to purchase or subscribe for securities is made, it will be made by applicable legal documents, which will require prospective investors to represent, among other things (in substance), that they are eligible investors, qualify as “accredited investors”, are familiar with and understand the terms of the offering and the applicable resale restrictions, acknowledge that any such purchase or subscription is being made on a private placement basis, have all requisite authority to make such investment, as well as representations as to access to information, investment intent and ability to bear the economic risk of loss of any such investment. This Presentation is qualified in its entirety by reference to those legal documents. The securities referred to herein have not been and will not be registered under the U.S. Securities Act of 1933 and are not being offered to the public in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and any other applicable securities laws. IN MAKING ANY INVESTMENT DECISION, INVESTORS MUST RELY ON THEIR OWN EXAMINATION OF THE CORPORATION AND THE TERMS OF ANY OFFERING THAT MAY BE MADE WITH RESPECT TO THE CORPORATION, INCLUDING THE MERITS AND RISKS INVOLVED. THE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE U.S. SECURITIES AND EXCHANGE COMMISSION OR BY ANY STATE SECURITIES COMMISSION OR REGULATORY AUTHORITY, NOR HAVE ANY OF THE FOREGOING AUTHORITIES OR ANY CANADIAN SECURITIES REGULATOR PASSED ON THE ACCURACY OR ADEQUACY OF THIS PRESENTATION. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE. You are urged to request any additional information you may consider necessary or desirable in making an informed investment decision with respect to the Corporation. You are invited to meet with representatives of the Corporation, and to discuss with, ask questions of, and receive answers from such representatives concerning information contained herein, and to obtain any additional information (to the extent that such representatives possess such information or can acquire it without unreasonable effort or expense) necessary to verify the information contained herein. Purchasing securities of the Corporation should be considered a risky and speculative investment and is appropriate only for investors who can absorb the possible loss of their entire investment. There is no public market for the securities of the Corporation and one may never develop. Therefore, investors may find it difficult to resell their securities. This Presentation contains “forward-looking” statements. We desire to take advantage of the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995 and we are including this statement for the express purpose of availing ourselves of the protections of such safe harbor with respect to all of such forward-looking statements. PURCHASER RIGHTS Statutory Rights of Action In certain circumstances, purchasers resident in certain provinces and territories of Canada are provided with a remedy for rescission or damages, or both, in addition to any other right they may have at law, where an offering memorandum (such as this Presentation) and any amendment to it contains a misrepresentation. For the purpose of the following summary, a "misrepresentation" means an untrue statement of a material fact or an omission to state a material fact that is required to be stated or that is necessary to make any statement not misleading or false in the light of the circumstances in which it was made. These remedies, or notice with respect thereto, must be exercised or delivered, as the case may be, by the purchaser within the time limits prescribed by the applicable securities legislation. The following summary is subject to the express provisions of the applicable securities laws, regulations and rules, and reference is made thereto for the complete text of such provisions. Such provisions may contain limitations and statutory defences not described herein on which the Corporation and other applicable parties may rely. Purchasers should refer to the applicable provisions of the securities legislation of their province for the particulars of these rights or consult with a legal adviser. The rights of action described below are in addition to and without derogation from any other right or remedy available at law to the purchaser and are intended to correspond to the provisions of the relevant securities legislation and are subject to the defences contained therein. May 2025 Legal Disclaimer 60
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The following is a summary of rights of rescission or damages, or both, available to purchasers resident in the province of Ontario, New Brunswick, Nova Scotia and Saskatchewan. If there is a misrepresentation herein and you are a purchaser under securities legislation in Ontario, New Brunswick, Nova Scotia and Saskatchewan you have, without regard to whether you relied upon the misrepresentation, a statutory right of action for damages, or while still the owner of the securities, for rescission against the Corporation. This statutory right of action is subject to the following: (a) if you elect to exercise the right of action for rescission, you will have no right of action for damages against the Corporation; (b) except with respect to purchasers resident in Nova Scotia, no action shall be commenced to enforce a right of action for rescission after 180 days from the date of the transaction that gave rise to the cause of action; (c) no action shall be commenced to enforce a right of action for damages after the earlier of (i) 180 days (with respect to purchasers resident in Ontario) or one year (with respect to purchasers resident in Saskatchewan and New Brunswick) after you first had knowledge of the facts giving rise to the cause of action and (ii) three years (with respect to purchasers resident in Ontario) or six years (with respect to purchasers resident in Saskatchewan and New Brunswick) after the date of the transaction that gave rise to the cause of action; (d) with respect to purchasers resident in Nova Scotia, no action shall be commenced to enforce a right of action for rescission or damages after 120 days from the date on which payment for the securities was made by you; (e) the Corporation will not be liable if it proves that you purchased the securities with knowledge of the misrepresentation; (f) in the case of an action for damages, the Corporation will not be liable for all or any portion of the damages that it proves do not represent the depreciation in value of the securities as a result of the misrepresentations; and (g) in no case will the amount recoverable in such action exceed the price at which the securities were sold to you. The foregoing is a summary only and is subject to the express provisions of the Securities Act (Ontario), the Securities Act (New Brunswick), the Securities Act (Nova Scotia) and the Securities Act (Saskatchewan), and the rules, regulations and other instruments thereunder, and reference is made to the complete text of such provisions contained therein. Such provisions may contain limitations and statutory defences on which the Corporation may rely. Notwithstanding that the Securities Act (British Columbia), the Securities Act (Alberta), and the Securities Act (Quebec) do not provide, or require the Corporation to provide, to purchasers resident in these jurisdictions any rights of action in circumstances where this presentation or an amendment hereto contains a misrepresentation, purchasers in British Columbia, Alberta and Quebec will be entitled to contractual rights of action for damages or rescission similar to the statutory rights provided to purchasers in Ontario. In Manitoba, the Securities Act (Manitoba), in Newfoundland and Labrador, the Securities Act (Newfoundland and Labrador), in Prince Edward Island, the Securities Act (PEI), in Yukon, the Securities Act (Yukon), in Nunavut, the Securities Act (Nunavut) and in the Northwest Territories, the Securities Act (Northwest Territories) provide a statutory right of action for damages or rescission to purchasers resident in those respective jurisdictions, in circumstances where this Presentation or an amendment hereto contains a misrepresentation, which rights are similar, but not identical, to the rights available to Ontario purchasers. May 2025 Legal Disclaimer 61
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FEATURE PLAY: DUVERNAY LIGHT OIL ACTIVITY ACCELERATING
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PrairieSky has a meaningful Fee Land position within the Duvernay oil window in both the East and West Shale Basins, with total royalty exposure of 909,000 acres. The play boasts large resource in place, high netback light oil, depth of inventory, and access to infrastructure. Industry activity in the play accelerated in 2024, with 33 wells rig released on PrairieSky acreage. WEST SHALE BASIN EAST SHALE BASIN Duvernay – Overview 63
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0 200 400 600 800boe/d Duvernay Royalty Production Oil NGL Gas West Shale Basin Duvernay – Driving Growth PrairieSky’s acreage in the West Shale Basin at Pembina/Willesden Green is ideally situated in an area of relatively thick Duvernay shale, and within the volatile oil thermal maturity window. Operators have seen a recent step-change improvement in overall capital efficiencies, with IP30 oil rates as high as ~1,000 bbl/d. West Shale Basin activity drove overall Duvernay royalty growth for PSK in 2024 of 55% y/y, at ~620 BOE/d (85% oil and liquids). PrairieSky has recently added significant Duvernay GORR acreage contiguous with its existing Fee Land in the West Shale Basin, which has not been included in the 2025 Royalty Playbook. 64
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2024 Royalty Revenue: $16 million Undiscounted Total Value: $2.5 billion Acreage Included in Future Development: 43% Development Locations: 1,060 Over 30 Years of Drilling Inventory Inventory Snapshot – Duvernay 699 498 681 377 0 100 200 300 400 500 600 700 800 900 Average Booked Reserves (2024 Drilling) Playbook Type Curve Duvernay Type Curve Initial Rate (BOE/d) Ultimate Recovery (MBOE) 81% Liquids 84% Liquids 82% Liquids 88% Liquids 65 Play Area Total Volume % Developed Fee GORR Total (MBOE) 2021 Royalty Playbook 50% 1,120 210 1,330 40,544 2023 Royalty Playbook 40% 960 150 1,110 31,534 2025 Royalty Playbook 43% 900 160 1,060 40,101 Duvernay Locations
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SPARTAN DELTA CORP . May 14, 2025 PRAIRIESKY ROYALTY INVESTOR DAY
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SPARTAN DELTA CORPORATE STRATEGY May 14, 2025 67 Three Pillar Strategy I. DUVERNAY DEVELOPMENT II. DEEP BASIN OPTIMIZATION III. DEEP BASIN CONSOLIDATION LARGE INVENTORY ESTABLISHED OIL AND CONDENSATE RICH RESOURCE PLAY UNDERUTILIZED INFRASTRUCTURE SUPPORTS GROWTH LIQUIDS-RICH GAS FREE FUNDS FLOW GENERATION IMPROVEMENTS IN CAPITAL EFFICIENCY TECHNICAL EXPERTISE OPERATIONAL AND G&A SYNERGIES FOUNDATIONAL ASSET PROVIDES M&A SPRINGBOARD
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SPARTAN DELTA CORP TSX SDE $/sh 2.75 MM 200 $MM 550 $MM 82 $MM 632 % 12%Management & Board Ownership Share Pri ce (1) Market Capitalization Common Shares Outstanding (1) Net Debt (2) Enterprise Value DEEP BASIN ~130,000 NET ACRES (>200 SECTIONS) $100-110 MM 2025E CAPITAL ~900 NET DRILLING LOCATIONS LIQUIDS-RICH GAS CORPORATE SUMMARY May 14, 2025 68 Building a Sustainable Energy Company CAPITALIZATION 1) As at closing May 14, 2025 2) As at March 31, 2025 Calgary, Alberta DUVERNAY ~320,000 NET ACRES (500 SECTIONS) $200-215 MM 2025E CAPITAL >600 NET DRILLING LOCATIONS OIL AND CONDENSATE GROWTH Edmonton, Alberta ABOUT SPARTAN DELTA CORP. Spartan is committed to creating value for its shareholders, focused on sustainability both in operations and financial performance. The Company’s culture is centered on generating Free Funds Flow through responsible oil and gas exploration and development. The Company has established a portfolio of high-quality production and development opportunities in the Deep Basin and the Duvernay. Spartan will continue to focus on the execution of the Company’s organic drilling program across its portfolio, delivering operational synergies in a respectful and responsible manner to the environment and communities it operates in. The Company is well positioned to continue pursuing optimization in the Deep Basin, participate in the consolidation of the Deep Basin fairway, and continue growing and developing its Duvernay asset. SPARTAN DELTA CORP. 39,000-41,000 BOE/D 2025E PRODUCTION $300-325 MM 2025E CAPITAL SDE Gas Plant
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SPARTAN’S STRATEGIC MILESTONES May 14, 2025 69 Continuously Generating Shareholder Value Bellatrix Acquisition Jun 2020 Inception Acquisition Feb 2021 Velvet Acquisition Aug 2021 TRACK RECORD OF EXECUTING STRATEGY Growth Through Targeted Strategic Acquisitions in a Depressed Market. Dominant Positions Secured in the Oil-Weighted Window of the Montney and the Liquids-Rich Deep Basin. Integration of Acquired Assets and Demonstration of the True Productive Potential at Gold Creek and Karr Through Execution of Drilling Program. Acceleration of Debt Repayment, Returning the Company to a Clean Balance Sheet Position, Allowing for Inaugural Special Dividend of $0.50/sh. Monetization of Gold Creek and Karr Montney Declaring $9.60/sh. in Dividends and Distributions. Creation and Distribution of Logan Energy Corp. at $0.35/sh. to Spartan Shareholders. 1 GROWTH TIMELINE Montney Divestiture May 2023 $635 MM EQUITY ISSUED $1,788 MM CUMULATIVE ADJUSTED FUNDS FLOW $1,809 MM DIVIDENDS AND DISTRIBUTIONS (2) 305% CUMULATIVE RETURN ON CAPITAL EMPLOYED (4) CORPORATE HIGHLIGHTS SINCE INCEPTION (1) Refocusing on the Deep Basin and Building a New Core Growth Area in the West Shale Basin Duvernay at a Low Entry Cost. $1,173 MM CUMULATIVE CAPITAL EXPENDITURES (3) 2 3 4 5 6 1) December 19, 2019, to March 31, 2025 2) Inclusive of $1,748 MM cash proceeds and the $60.6 MM Logan distribution 3) Cumulative Capital Expenditures Before A&D 4) ROCE = EBIT/Total Capital Expenditures (including A&D) $10.45/sh. DIVIDENDS AND DISTRIBUTIONS (2) Duvernay Acquisitions Nov 2023 - Current
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Crude Oil & Condensate bbls/d 3,297 5,600 Natur al Gas Liquids (NGL s) bbls/d 9,209 9,700 Natur al Gas MMcf/d 154 148 Average Production boe/d 38,166 39,000 - 41,000 Operating Expenses $/boe (5.90) (6.20) Transportation Expenses $/boe (1.54) (2.11) Operating Netback, before Hedging $/boe 11.68 18.39 Settlement on Commodity Derivative Contracts $/boe 2.43 (0.10) Operating Netback, after Hedging $/boe 14.11 18.29 G&A $/boe (1.31) (1.34) Adjusted Funds Flow $MM 165 223 Capital Expenditures, before A&D $MM 162 300 - 325 Year Ended Net Debt (Surplus) $MM 148 148 WTI US$/bbl 75.73 72.00 AECO C$/GJ 1.36 2.20 FX US$/C$ 1.37 1.43 2025 GUIDANCE May 14, 2025 70 Optimizing the Deep Basin and Growing the Duvernay 1) The financial performance measures are based on the midpoint average production forecast; numbers may not add due to rounding 2) FY2024 actuals to 2025 guidance, before hedging GUIDANCE (1) GUIDANCE FY 2025 ACTUALS FY 2024 GUIDANCE HIGHLIGHTS 70% INCREASE IN OIL & CONDENSATE PRODUCTION (2) 57% INCREASE IN OPERATING NETBACK (2) ADJUSTED FUNDS FLOW SENSITIVITIES ~$8.0 MM AECO +/ - $0.25/GJ ~$10 MM WTI +/ - US$5/BBL ~$7.0 MM FX +/ - $0.05 $100-110 MM 2025E DEEP BASIN CAPITAL $200-215 MM 2025E DUVERNAY CAPITAL 18 2025E DEEP BASIN NET WELLS COMPLETED AND ONSTREAM 15 2025E DUVERNAY NET WELLS COMPLETED AND ON - STREAM
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DUVERNAY DEVELOPMENT May 14, 2025 71 Prolific Liquids-Rich Shale Asset Offers Significant Scalability and Commerciality WEST SHALE BASIN DUVERNAY Spartan has established one of the largest positions in the oil and condensate rich West Shale Basin Duvernay, consolidating fragmented and undercapitalized acreage Spartan has access to available egress and existing underutilized infrastructure to support rapid growth and development Spartan has constructed water infrastructure to reduce completion costs Drilling 16 (14 net) wells and completing and bringing on-stream 17 (15 net) wells in 2025 Drilled 6.0 (4.2 net) wells in Q1 2025 Targeting production growth to 25,000 BOE/d SPARTAN DUVERNAY HIGHLIGHTS CARROT CREEK DUVERNAY PEMBINA DUVERNAY WILLESDEN GREEN DUVERNAY ~320,000 NET ACRES (500 NET SECTIONS) ~70% AVERAGE LIQUIDS PRODUCTION ~180% ANNUALIZED PRODUCTION GROWTH RATE $200-215 MM 2025 CAPITAL ~25,000 BOE/D 5 - YEAR TARGETED PRODUCTION >600 NET DRILLING LOCATIONS (~70 BOOKED)
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DUVERNAY DEVELOPMENT May 14, 2025 72 Expansive Position Across the Willesden Green & Pembina Fairway CORE DEVELOPMENT TYPE CURVES 0.8-1.1 MMboe ESTIMATED RECOVERY PER WELL 800-1,200 BOE/D ESTIMATED IP30 RATE $11.0-12.5 MM ESTIMATED DRILL, COMPLETE,EQUIP, & TIE - IN COSTS 16-12-044-04W5 • ~1,394 BOE/D IP30 • 82% liquids 5 - YEAR PRODUCTION TARGET 01-11-044-03W5 • ~937 BOE/D IP30 • 92% liquids 09-05-042-03W5 • ~1,029 BOE/D IP30 • 87% liquids 03-26-042-04W5 • ~1,166 BOE/D IP30 • 90% liquids SDE W.I. Lands SDE Operated Duvernay Wells SDE 2025 Drilled SDE 2025 Upcoming Drills Industry Duvernay Wells Joint Venture Area
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www.SpartanDeltaCorp.com 73
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DISCLAIMER May 14, 2025 74 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“, “guidance”, “goals” or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information in this presentation may include, but is not limited to, statements about: the corporate strategy, objectives, strengths and focus of Spartan Delta Corp. (“Spartan” or the “Company”), including commodity diversification, oil weighted production, continued optimization of its Deep Basin asset, participation in the consolidation of the Deep Basin fairway, and advancement of the Company’s strategy in the West Shale Basin Duvernay (the “Duvernay”); the intentions of management with respect to its strategy, growth and business plan; Spartan's ability to deliver sustainable free funds flow from its assets; target capital efficiency improvements in the Deep Basin; expectations regarding Spartan’s updated 2025 guidance and drilling program, including the location of wells, scheduled drilling and completion dates and the timing of expected pay out from such wells; the scale and repeatability of Spartan's drilling inventory, including the expectation that Spartan can continue growing the business organically with decades of high-quality inventory; Spartan's intentions to maintain balance sheet flexibility to allow Spartan to take advantage of future opportunities; Spartan’s hedging strategy and anticipated benefits therefrom; Spartan plans to deliver strong operational performance, reduce debt and deliver self-funding growth in core area; Spartan's production forecasts; decline rates; Indigenous partnerships; predictions regarding commodities pricing and industry fundamentals, including natural gas demand and supply, and the effectiveness of Spartan's risk management strategies in respect thereof; and the continuation of Spartan's strategic partnerships, and expected benefits therefrom. Statements relating to “production reserves“, recovery, costs and valuation 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 performance of Spartan’s management team and board, 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 integration of recently acquired assets into Spartan’s operations, the successful application of drilling, completion and seismic technology, the Company’s ability to secure sufficient amounts of water, prevailing weather and break-up conditions and access to drilling locations, commodity prices, price volatility, price differentials and the actual prices received for products, impact of inflation on costs, royalty regimes and exchange rates, the application of regulatory and licensing requirements, the availability of capital, labour and services, Spartan's ability to complete planned capital expenditures within budgeted cost estimates, the ability to market oil and gas successfully, and the creditworthiness of industry partners. 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, 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, wars, changes in legislation (including but not limited to tax laws, royalty regimes and environmental legislation), the risk that the new U.S. administration imposes tariffs on Canadian goods, including crude oil and natural gas, and that such tariffs (and/or the Canadian government’s response to such tariffs) adversely affect the demand and/or market price for the Company’s products and/or otherwise adversely affects the Company, 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, ongoing military actions in the Middle East and between Russia and Ukraine have the potential to threaten the supply of oil and gas from those regions. The long-term impacts of the actions between these nations remains uncertain. Please refer to the Spartan's most recent Annual Information Form and Management Discussion and Analysis (MD&A) for additional risk factors relating to Spartan, which can be accessed either on Spartan's website at www.spartandeltacorp.com or under the Company’s SEDAR+ profile on www.sedarplus.ca. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date hereof, and to not use such forward-looking information for anything other than its intended purpose. The forward-looking information contained in this presentation 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 presentation is expressly qualified by this cautionary statement. FOFI. This presentation contains future-oriented financial information and financial outlook information (collectively, "FOFI") about Spartan's prospective results of operations, production (including targeted Duvernay production of 25,000 BOE/d), updated 2025 guidance, working capital, capital efficiency, capital expenditures, enterprise value, operating netback, share price, investment yield, net debt (surplus), adjusted free funds flow, free funds flow, NPV10, operating costs, cost reductions and components thereof, all of which are subject to the same assumptions, risk factors, limitations and qualifications as set forth in the above paragraphs. FOFI contained in this presentation was approved by management 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 and its management believe that FOFI has been prepared on a reasonable basis, reflecting management’s best estimates and judgements, and represent, to the best of management’s knowledge and opinion, the Company’s expected course of action. However, because this information is highly subjective, it should not be relied on as necessarily indicative of future results. 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. Changes in forecast commodity prices, differences in the timing of capital expenditures, and variances in average production estimates can have a significant impact on the key performance measures included in Spartan’s guidance. The Company’s actual results may differ materially from these estimates. Third Party Information. Certain information contained herein has been obtained from published 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 purpose used herein, none of the directors, officers, owners, managers, partners, consultants, shareholders, employees, affiliates or representatives assumes any responsibility for the accuracy of such information. Some of the sources cited in this presentation have not consented to the inclusion of any data from their reports, nor has Spartan sought their consent.
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DISCLAIMER May 14, 2025 75 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 this presentation are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil. Product Types. Throughout this presentation, "crude oil" or "oil" refers to light and medium crude oil product types as defined by National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). Condensate is a natural gas liquid as defined by NI 51-101. References to "natural gas liquids" or "NGLs" throughout this presentation comprise of pentane, butane, propane, and ethane, being all NGLs as defined by NI 51-101 other than condensate, which is disclosed separately because the value equivalency of condensate is more closely aligned with crude oil. References to "natural gas" or "gas" relate to conventional natural gas. References to "liquids" includes crude oil, condensate, and NGLs. The Company has disclosed condensate as combined with crude oil and/or separately from other natural gas liquids in this press release since the price of condensate as compared to other natural gas liquids is currently significantly higher and the Company believes that this crude oil and condensate production provides a more accurate description of its operations and results therefore. Short Term Results. References in this presentation to peak rates, initial production rates, IP30 rates and other short-term production rates are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long-term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production of Spartan. Reserves Disclosure. All reserves information in this presentation relating to Spartan’s year-end reserves were prepared by McDaniel & Associates Consultants Ltd. ("McDaniel") effective as of December 31, 2024 (the "McDaniel Report"), in accordance with NI 51-101 and the most recent publication of the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook"). All reserve references in this presentation are "Company share reserves". Company share reserves are the applicable 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 estimated future amounts presented in the tables above represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained, and variances could be material. The recovery and reserve estimates of the 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. All evaluations and summaries of future net revenue are stated prior to the provision for interest, debt service charges or general and administrative expenses and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimate future capital expenditures. Oil and Gas Metrics. This presentation contains metrics commonly used in the oil and natural gas industry which have been prepared by management, such as “IP30”, "operating netback“, and "NPV10". These terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare our operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this presentation, should not be relied upon for investment or other purposes. “IP30” means average production for the first 30 days that a well is onstream. "Operating Netback" see "Non-GAAP Measures and Ratios". "NPV10" is the anticipated net present value of the future net operating income after capital expenditures, discounted at a rate of 10% (before tax). Type Curves. Type curve disclosure presented herein represents estimates of the production decline and ultimate volumes expected to be recovered from wells over the life of the well. The reservoir engineering and statistical analysis methods utilized are broad and can include various methods of technical decline analyses, and reservoir simulation all of which are generally prescribed and accepted by the COGE Handbook and widely accepted reservoir engineering practices. These type curves were generated by Spartan's internal qualified reserves evaluators. These type curves incorporate the most recent data from actual well results and would only be representative of the specific drilled locations. There is no guarantee that Spartan will achieve the estimated or similar results derived therefrom. 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 / Inventory. 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 McDaniel Report and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on Spartan’s 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. 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 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.
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DISCLAIMER May 14, 2025 76 Non - GAAP Measures and Ratios : This presentation contains certain financial measures and ratios, as described below, which do not have standardized meanings prescribed by International Financial Reporting Standards ("IFRS Accounting Standards") or Generally Accepted Accounting Principles ("GAAP"). As these non-GAAP financial measures are commonly used in the oil and gas 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 or ratios for other companies where similar terminology is used. The non-GAAP measures and ratios used in this presentation, represented by 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 viewed as an alternative to cash provided by operating activities, net income or other measures of financial performance calculated in accordance with IFRS Accounting Standards. Please refer to the Company's most recent MD&A, for additional information relating to non-IFRS Accounting Standards measures, including a reconciliation to the nearest IFRS Accounting Standard measures. The MD&A can be accessed either on Spartan’s website at www.spartandeltacorp.com or under the Company’s SEDAR+ profile on www.sedarplus.ca. “Operating Income, before hedging” abbreviated as “NOI”, is calculated by Spartan as oil and gas sales, net of royalties, plus processing and other revenue, less operating and transportation expenses. “Operating Income, after hedging” is calculated by adjusting Operating Income for realized gains or losses on derivative financial instruments including settlements on acquired derivative financial instrument liabilities (together a non-GAAP measure “Settlements on Commodity Derivative Contracts”). The Company refers to Operating Income expressed per unit of production as an “Operating Netback” and reports the Operating Netback before and after hedging, both of which are non-GAAP financial ratios. Spartan considers Operating Netback an important measure to evaluate its operational performance as it demonstrates its field level profitability relative to current commodity prices. “Adjusted Funds Flow” or “AFF” is reconciled to cash provided by operating activities excluding changes in non-cash working capital, adding back transaction costs on acquisitions and dispositions, and deducting the principal portion of lease payments. Spartan utilizes Adjusted Funds Flow as a key performance measure in the Company’s annual financial forecasts and public guidance. Transaction costs, which primarily include legal and financial advisory fees, regulatory and other expenses directly attributable to execution of acquisitions and dispositions, are added back because the Company’s definition of Free Funds Flow excludes capital expenditures related to acquisitions and dispositions. For greater clarity, incremental overhead expenses related to ongoing integration and restructuring post-acquisition are not adjusted and are included in Spartan’s general and administrative expenses. Lease liabilities are not included in Spartan’s definition of Net Debt (non-GAAP measured defined herein) therefore lease payments are deducted in the period incurred to determine Adjusted Funds Flow. The Company refers to Adjusted Funds Flow expressed per unit of production as an “Adjusted Funds Flow Netback”. “AFF per share” is a non-GAAP financial ratio used by Spartan as a key performance indicator. AFF per share is calculated using the same methodology as net income per share, however the diluted weighted average common shares outstanding for AFF may differ from the diluted weighted average determined in accordance with IFRS Accounting Standards for purposes of calculating net income per share, due to non-cash items that impact net income only. "Free Funds Flow” or “FFF” is calculated by Spartan as Adjusted Funds Flow less Capital Expenditures before A&D, which is also a non-GAAP financial measure (defined herein). Spartan believes Free Funds Flow provides an indication of the amount of funds the Company has available for future capital allocation decisions such as to repay long-term debt, reinvest in the business or return capital to shareholders. “Capital Expenditures before A&D” includes capital expenditures on exploration and evaluation assets and property, plant and equipment, before acquisitions and dispositions. The directly comparable GAAP measure to capital expenditures is cash used in investing activities. “Adjusted Net Capital Acquisitions” is used by Spartan to measure the aggregate of cash, debt and share consideration used to acquire crude oil and natural gas assets, net of cash proceeds received on dispositions. The most directly comparable GAAP measures are acquisition costs and disposition proceeds included as components of cash used in investing activities. Adjusted Net Capital Acquisitions is considered by management to be more representative of the total transaction value than cash consideration alone. “Total Capex (including A&D)” is used by Spartan in the calculation of ROCE which is also a non-GAAP financial measure (defined herein). Total Capex (including A&D) is calculated as the sum of Capital Expenditures before A&D and Adjusted Net Capital Acquisitions which are non-GAAP measures defined above. “Net Debt (Surplus)” includes long-term debt, net of Adjusted Working Capital. Net Debt (Surplus) and Adjusted Working Capital are both non-GAAP financial measures. “Adjusted Working Capital” is calculated as current assets less current liabilities, excluding derivative financial instrument assets and liabilities, lease liabilities and the deferred premium on flow through shares (if applicable). As at March 31, 2025, the Adjusted Working Capital (Surplus) deficit includes cash and cash equivalents, restricted cash, accounts receivable, prepaid expenses and deposits, accounts payable and accrued liabilities and the current portion of decommissioning obligations. Net Debt (Surplus) is used by the Company as a measure of its financial position and liquidity, however it is not intended to be viewed as an alternative to other measures calculated in accordance with IFRS Accounting Standards. "Enterprise Value" is calculated as the Market Capitalization of the Company plus Net Debt, where "Market Capitalization" is defined as the total number of common shares outstanding multiplied by the price per share at a given point in time. "Capital Efficiency" is the amount spent to add an additional barrel a day of production to a company's annual exit production. “Cumulative Return on Capital Employed” or “ROCE” is calculated as Earnings before Interest and Taxes (EBIT) divided by Total Capital (including A&D), both of which are non-GAAP financial measures (defined herein). “EBIT” is calculated by adding back Cash Financing Expenses to net income before income taxes. References to “Cash Financing Expenses” includes interest and fees on long-term debt, net of interest income, and excludes financing costs related to lease liabilities and accretion of decommissioning obligations. US Disclaimer. This presentation is not an offer of the securities for sale in the United States. The securities have not been registered under the U.S. Securities Act of 1933, as amended, and 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 buy nor shall there be any sale of the securities in any state in which such offer, solicitation or sale would be unlawful. Compounded annual return if invested in the equity financing and held until June 20, 2023, inclusive of the $0.50 per share special dividend paid January 16, 2023. Comparison is the return if invested into XEG over the exact same time-period inclusive of XEG dividends as well. $2.7 billion of equity value calculated as follows: $14.99 per share (closing SDE price on June 20, 2023) plus $0.50 per share special dividend paid on January 16, 2023, plus $0.10 per share special dividend paid on July 31, 2023, multiplied by 173.2 million common shares. Compounded annual return of Spartan entities and XEG calculated if invested from the initial public equity financing and held until exit for SPE, STO, and SPE, and for SDE from initial financing until June 20, 2023. SDE price calculated using the closing price on June 20, 2023. Both XEG and SDE are inclusive of dividends.
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GUEST SPEAKER QUESTIONS? 77
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BREAK
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FEATURE PLAYS: MONTNEY AND SAGD + SE SASKATCHEWAN LIGHT OIL & OTHER OPPORTUNITIES
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Montney Oil & Gas - Overview Montney royalty production averaged ~1,690 BOE/d (27% liquids) in 2024. ~300,000 acres of predominantly GORR Lands within Play Areas 72 wells drilled on Royalty Lands from 2023-2024 2,180 future locations in inventory 80
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Two Rivers Montney Oil – Near Term Growth with Running Room PSK holds a GORR on ~114,000 acres of Montney rights in the Two Rivers area of Northeast British Columbia. The Montney is 325m thick with development potential in both the Upper and Lower Montney, and future upside in the Middle and Basal Montney. Three recently completed wells in the Lower Montney delivered strong test results averaging 1,624 BOE/d including 989 bbl/d of light oil. The operator expects a total of 9 wells to be brought on production from this pad in Q2 2025 following completion of facility construction. 81
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Wembley Montney – High Impact Oil Growth PSK holds a GORR on 6.5 sections of Montney rights close to the boundary of the oil and liquids-rich gas windows of the Montney in the Wembley region of Alberta. A total of 4 sections of Montney have been developed, which contributed ~530 BOE/d (44% liquids) to corporate royalty production in 2024. Multi-layer Montney development potential exists on the remaining 2.5 undeveloped sections, which should provide meaningful production and reserve additions in the future. One Montney well was recently licensed on this acreage. 82
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Kakwa/Karr Condensate-Rich Gas – Realizing Future Potential PSK holds a 12.5% GORR on a single section of Montney rights at Kakwa/Karr , acquired from Range Royalty in 2015. In 2023, a single Montney well was licensed. Today, the operator has recently finished drilling an 8-well pad, with completion expected to follow later in the year. With an estimated 6.25% Royalty Interest on the 8-wells located in the condensate-rich gas fairway, the pad is expected to be impactful to near-term royalty volumes. 2023 Investor Day 2025 Investor Day 83
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SAGD Exposure - Low Decline, Long Reserve Life 0 200 400 600 800 1,000 1,200 1,400 2017 2018 2019 2020 2021 2022 2023 2024 Oil Production (bbl/d) LINDBERGH ONION LAKE PrairieSky’s producing SAGD assets are focused in two core areas, Lindbergh in East Central Alberta, and Onion Lake in West Central Saskatchewan. Both projects are low decline, long life assets with expansion potential. Total SAGD royalty production volumes have recently grown to >1,200 bbl/d, driven by increased production at Lindbergh. Growth to >2,000 bbl/d is expected by the end of the decade as Lindbergh Phase 2 is developed. PSK SAGD Royalty Production 84
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Lindbergh Expansion Expansion underway to grow Lindbergh volumes to 43,000 bbl/d by 2030, from a current ~20,000 bbl/d. This is expected to add ~920 bbl/d of royalty oil volumes net to PrairieSky. With OOIP of 680 MMbbl, the operator estimates a Reserve Life Index of ~30 years following the completion of the expansion. Zero value has been ascribed to future development potential of the offsetting Muriel Lake asset (67 MMbbl OOIP) in the 2025 Royalty Playbook. 43,000 bbl/d 20,000 bbl/d Adapted from Strathcona Resources Investor Day Presentation, November 14, 2024. LINDBERGH PHASE 2 85
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Small Scale SAGD Focused in West Central Saskatchewan, PrairieSky has exposure to future modular SAGD projects with production potential in the 5,000-10,000 bbl/d range. Delineation of thick, heavy-oil bearing Colony, Waseca and Lloyd channel complexes is underway on PSK acreage at Kelfield, Handel, Spruce Lake and Meota, which offer significant future upside. Zero value has been assigned to future small scale SAGD projects in the 2025 Royalty Playbook. Kelfield Waseca Type Log, PSK Fee SPRUCE LAKE HANDEL MEOTA KELFIELD 86
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SE Saskatchwan – Multilaterals Targeting Light Oil SE Saskatchewan and Manitoba contribute $2.3 billion of undiscounted total value in the 2025 Royalty Playbook (+118% from 2023). Play areas in the Bakken and Mississippian light oil plays have expanded and well densities have increased with recent industry activity. Multilateral drilling has been recently used to exploit light oil in tight reservoirs (North Viewfield Bakken) and thin stacked zones (Frobisher at Steelman) to greatly enhance play economics. PrairieSky has identified a total of 2,320 locations, including 1,660 on Fee Land. Recently acquired Fee Land in SE Saskatchewan (January 2025) has been excluded from the 2025 Royalty Playbook. STEELMAN VIEWFIELD 87
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CCS and Other Opportunities – Future Optionality Meadowbrook CCS PSK is a 28.5% JV partner in the CO2 sequestration and storage project at Meadowbrook, located near Morinville, Alberta, in the province’s industrial heartland. The project is anticipated to be developed in phases, initially small scale (<100,000 tonnes per annum) with potential to scale up to >3Mtpa. The project received CO2 sequestration approval from the AER in February 2025. Potash Recurring income from leases in central Saskatchewan. $1.6 million in royalty revenue in 2024 from two counterparties. Helium Received first helium royalty revenues in 2024. Three current leasing arrangements covering 5,240 acres. Lithium Active leasing arrangement covering ~192 gross sections on which operator continues its technical evaluation through its pre-feasibility study. Lithium Crown land sales in SE Saskatchewan totaled >$8 million in 2024. Meadowbrook Project Area 88
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FINANCIAL UPDATE
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Revenue Generation – Oil Royalty Production 90 Oil royalty production is shown on a production month basis, replacing accruals and compliance amounts with actuals. As a result, oil royalty production may not match oil royalty volumes in PrairieSky’s MD&A for the corresponding year. PSK has continued to see strong royalty production growth in its heavy oil portfolio. Based on operator budgets, PSK expects growth to continue. Duvernay production will add light oil production volumes with strong netbacks.
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Revenue Generation – Natural Gas Royalty Production 91 PSK has a perpetual call option on natural gas. PSK benefits directly from an increase in AECO natural gas pricing through increased royalty revenue and increased activity on our Royalty lands. With PSK’s significant natural gas reserves and resource in place, PSK has the opportunity to realize significant future upside in a stronger natural gas pricing environment. There are a number of short, medium and long-term opportunities for natural gas: LNG offtake Petrochemical plants Electricity Data centres Blue hydrogen Natural gas and NGL royalty production and revenue are shown on a production month basis, replacing accruals and compliance amounts with actuals. As a result, royalty production may not match royalty volumes in PrairieSky’s MD&A for the corresponding year.
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Higher Margin, Lower Risk, Low Impact of Cost Inflation Margin Summary ($/BOE) PrairieSky Royalty offers higher margins than conventional working interest production Providing the same revenue per BOE, a royalty barrel realizes significantly higher margins than working interest models No abandonment or environmental liabilities Low sensitivity to cost inflation as costs are allocated to the working interest owner No capital spending requirements Revenue (63% Liquids Production)(1) $52.58/boe Illustrative Working Interest Operator PrairieSky Royalty Incurred by Working Interest Operators Operating Margin $19.48/BOE 37% of Revenue F&D(2) ($12.00/BOE) Operating / TransportationCosts ($13.00/BOE) Royalties ($8.10/BOE) Royalty Operating Margin(3) $52.01/BOE 99% of Revenue (1) Excludes the impact of Other Revenues (lease rentals, bonus consideration,etc.) for the three months ended March 31, 2025. (2) Excluding acquisitions and net change in future development capital. (3) See Non-GAAP Measures and Ratios. Amounts per BOE for PrairieSky Royalty are for the three months ended March 31, 2025. Production & Mineral Tax ($0.57/BOE) No royalties payable to the Crown on Fee Lands 92
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Other Revenues Generated From Royalty Properties 93 PrairieSky generates other revenues primarily from upfront bonus consideration and lease rentals, both earned from leasing Fee Lands. Bonus consideration has grown steadily since 2020 due to active leasing. Since IPO, our leasing strategy has evolved to maximize value and opportunities: Zonal Leasing Lease Rentals by Product Increasing rentals with inflation Shorter-term leasing
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Expenses 94 PSK’s simple cost structure includes production and mineral taxes and administrative expenses. Production and mineral expenses are calculated based on production volumes and price in Alberta and on a per acre basis in Saskatchewan. PrairieSky continues to adopt technology to scale our business. See Non-GAAP Measures and Ratios.
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Bank Debt 95 PrairieSky’s credit facility is $350 million with a syndicate of Canadian banks. Credit facility provides for a permitted increase up to $600 million. At March 31, 2025, PrairieSky’s bank debt totaled $220.1 million. Currently borrowing at ~4.75%; interest is deductible for tax purposes.
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Taxes 96 PrairieSky's tax pool balances are deductible at ~10% per year, providing tax shelter in 2025 to the first $131 million of taxable income.
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VALUATION & SHAREHOLDER RETURNS
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Adding Value Through the Cycles 98 Peers need to acquire at all points in the cycle. PSK can acquire at cycle lows and grow through leasing land at the highs. Strong balance sheet maintained for optionality at cycle lows, including share buybacks or opportunistic acquisitions. How do you manage a counter-cyclical business and take advantage of disconnects?
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Leasing Activity – Make Hay When the Sun Shines 99
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Countercyclical Capital Deployment History of acquiring assets near low points of the commodity cycle, with major acquisitions completed between US$44-70/bbl WTI. Share buybacks have been completed across a time period when WTI averaged US$57/bbl including ~$86 million of share repurchases in Q2/Q3 2020 when WTI averaged US$38/bbl and $90 million of share repurchases in Q1 2025. Spur Marten Hills $155MM Heritage $728MM IPO Onion Lake $109MM Range Royalty $625MM Canadian Natural $1.7B Initial Clearwater Lindbergh $250MM 100 $90MM Share Buyback
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PrairieSky Call Options 101 PrairieSky has a larger bundle of Call Options than any of its peers. 1. Duvernay – light oil growth West Shale oil development underway, huge growth potential High proportion of Fee Lands in the core of the play 2. Clearwater – secondary recovery upside Declines trending lower in the play Waterflood and polymer pilots initiated outside of core areas 3. Primary Heavy Oil – early stages of Mannville Stack development New technology unlocking heavy oil resource Testing of new plays and concepts moving forward 4. Small Scale SAGD – future growth Large OOIP resource identified, future discoveries anticipated on trend Potential projects add low-decline, long-life production 5. Natural Gas Pricing – minimal gas contribution from gas to current royalty revenue Leverage to improved pricing 1.2 TCF of future potential and 1.4 TCF of total volumes in 2025 Asset Book 6. New Discoveries in the Basin 18.5 Million Royalty acres with exposure across the WCSB Fee simple land includes all minerals from surface to basement
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Optionality Through Technology 102 q2als.com lycosenergy.com Decades of Optionality through future technology developments: multilateral configurations and application to new formations/plays small scale SAGD, and thermal application expansion in heavy oil drilling fluid systems, pump designs, integrated production strings completion optimizations Small tweaks to drilling, completion and production methods and designs can have a large impact on value. WhaleSharkTM Downhole Separator Fishbone Multilateral Well
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Value of Fee Ownership 103 (1) Cash flow estimate for TPL based on published estimates from Texas Capital Securities. Cash flow estimate for PSK based on average of analyst estimates of funds from operations post Q1/25 reporting.
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Shareholder Returns 104 PSK’s perpetual ownership in royalty assets provides the opportunity for optionality and growth at a lower risk.
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Share Price Performance Relative to Capped Energy Index 105
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PrairieSky versus Other Industries 106 (1) Midstream group includes ALA, ENB, KEY, PPL, SOBO, and TRP. (2) Rails group includes CNR and CP. (3) Mining Royalty group includes FNV and WPM. (4) Source: Bloomberg, SNL Financial, Factset , company reports, and CIBC World Markets as of April 30, 2025. See Non -GAAP Measures and Ratios.
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PrairieSky versus REITs 107 PrairieSky could repurchase all of its common shares in the time it takes for the REITs to repay debt. REITs trade at an average 17x 2025E EV/EBITDA versus PSK at 12x(1). (1) Source: Bloomberg, SNL Financial, Factset , company reports, and CIBC World Markets as of April 30, 2025. See Non -GAAP Measures and Ratios. (2) Net debt is bank debt (current and long term) plus current liabilities less current assets. (3) REIT AFFO is Funds from Operations (FFO) adjusted for recoverable and non-recoverable maintenance capital expenditures, tenant improvements, straight -line rent adjustments and other items. (4) PSK forecasted FFO is based on the average of analyst estimates post PrairieSky’s Q1 2025 results. See Assumptions. (5) Assumes REITs and PSK do not pay dividends.
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10 Year Funds from Operations Generation 2024 Average Royalty Production 25,186 BOE/d(1) A $0.50/Mcf increase in AECO increases 10-year cash flow by $0.1 billion. (1) For the year ended December 31, 2024. With no capex requirements, Funds from Operations are fully available for shareholder returns. 108
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Capital Allocation – Share Buyback Example 109 The following chart outlines scenarios where PrairieSky allocates 100% of its Funds from Operations to repurchase and cancel its shares. At the end of 10 years, using conservative production and pricing scenarios, PSK could buy back the majority of its shares outstanding. Assumes share price does not change.
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Outcomes – 2023 Investor Day 110 $- $20 $40 $60 $80 $100 $120 $140 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 Share Price Year 24,000 BOE/d, WTI US$60 26,000 BOE/d, WTI US$70 28,000 BOE/d, WTI US$80 PSK including $6.68 in dividends March 31, 2023 PSK excluding dividends PrairieSky share price of $23.25 + dividends of $8.66 = $31.91 per share
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$- $20 $40 $60 $80 $100 $120 $140 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 Share Price Year Flat Production, WTI US$60 Production Growth 2.5% CAGR, WTI US$70 Outcomes – 2025 Investor Day 111 March 31, 2025 PSK including $8.66 in dividends PSK excluding dividends
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QUESTIONS? 112
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Leadership Team Board of Directors Margaret A. McKenzie, Chair of the Board Corporate Director, Former VP, Finance and Chief Financial Officer of Range Royalty and prior thereto was VP, Finance and Chief Financial Officer of Profico Energy Management Ltd. Director of Canadian National Railway Company Andrew M. Phillips, President & CEO / Director Anna M. Alderson Corporate Director, Former Audit Partner KPMG LLP specializing in energy and financial services Director of Tenaz Energy Corp. Anuroop S. Duggal Private Investor and Corporate Director, Former Partner at 3G Capital Partners and Adjunct Professor at Columbia Business School Director of Calfrac Well Services Ltd. and Optiva Inc. P. Jane Gavan President, Asset Management of Dream Unlimited Corp. Board of Directors of Dream Unlimited Corp., Colliers International and on the Board of Trustees of Dream Office REIT and Dream Residential REIT Glenn A. McNamara Corporate Director, Former President & Chief Executive Officer and Director of Heritage Resources LP, Former President of BG Canada and ExxonMobil Canada Energy Director of Whitecap Resources Inc. and Parex Resources Inc. Sheldon B. Steeves Corporate Director, Previously President & CEO of EchoEx; Executive Vice President & COO at Renaissance Energy Ltd. Senior leadership team offers unique expertise managing royalty assets, significant technical capabilities and broad, long-standing industry relationships. Executive Team Andrew M. Phillips, President & CEO / Director Previously, President, CEO & Director of Home Quarter Resources (acquired by a public oil and gas company in 2014) Extensive experience in the oil & gas industry with past senior roles at Profico Energy Management and Renaissance Energy Pamela P. Kazeil, Senior VP Finance & Chief Financial Officer Previously, EVP and Chief Financial Officer of Sinopec Canada and prior thereto VP, Finance of Daylight Energy Formerly VP Finance of Sword Energy Ltd. and held increasingly senior roles at its predecessor, Thunder Energy Trust, including VP Finance and CFO Daniel J. Bertram, VP Business Development & Chief Commercial Officer Previously, Senior Vice-President and Chief Strategy Officer at Superior Plus Corp. Formerly VP, Business Development at Certarus Ltd. and prior to VP Business Development at Alaris Royalty Corp. Michael T. Murphy, VP Geosciences & Capital Markets Previously, Research Analyst at BMO Capital Markets Formerly Senior Research Associate at Macquarie Capital Markets Canada
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The following flat pricing assumptions were used in preparing the Undiscounted Booked Value(1) and Undiscounted Future Potential in the 2025 PrairieSky Royalty Playbook and this Investor Day Presentation (please see Pricing Assumptions on page 26 and Assumptions & Terminology on page 47 of the 2025 PrairieSky Royalty Playbook for further information): (1) The Undiscounted Booked Value does not match the year-end GLJ Report as the GLJ Report was prepared using the pricing assumptions disclosed in PrairieSky’s AIF under the heading “Pricing Assumptions – Forecast Prices and Costs”. Estimate of PrairieSky’s 2025 funds from operations, and funds from operations per share used in the presentation are based on the average of 10 analyst estimates provided post PrairieSky’s Q1 2025 results including ATB Capital Markets, BMO Capital Markets, Canaccord Genuity Capital Markets, CIBC World Markets, National Bank of Canada Financial Markets, Peters & Co. Limited, Raymond James Ltd., RBC Capital Markets, Scotiabank, and TD Securities Inc. Assumptions 114
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Disclaimer & Cautionary Statements 115 Third-Party and Public Information Except where otherwise stated, the disclosure in this Investor Day Presentation relating to the Royalty Properties and operations on such properties is based on information publicly disclosed by the operators of these properties and information/data available in the public domain as at March 31, 2025. However, as a royalty owner, PrairieSky may not have complete, current and accurate information relating to the Royalty Properties described in this Investor Day Presentation. Additionally, PrairieSky may, from time to time, receive operating, technical and financial information from operators on the Royalty Properties, which it is not permitted to disclose to the public. PrairieSky is dependent on operators on the Royalty Properties and their qualified persons to provide information to PrairieSky or on publicly available information to prepare required disclosure pertaining to the Royalty Properties and generally has limited ability to independently verify such information. Although PrairieSky does not have any knowledge that such information may not be accurate, there can be no assurance that such third-party information is complete or accurate. Some information publicly reported by operators may relate to a larger property than the area covered by PrairieSky’s royalty interest. PrairieSky’s royalty interests often cover only a portion of the publicly reported reserves and production of the property. Guest slides and presentations included herein have been provided by our operating partners and have not been independently verified by PrairieSky. Cautionary Statement on Forward-Looking Information This Investor Day Presentation contains "forward-looking information" and "forward-looking statements" within the meaning of applicable securities laws, which may include, but are not limited to: statements with respect to future events or future performance; management’s expectations regarding PrairieSky’s growth and realization of future value from the Royalty Properties; PrairieSky’s intention to distribute the majority of cash flow in the form of dividends and share repurchases over time; results of operations of third parties active on the Royalty Properties; estimated future revenues; carrying book value of assets and future potential values related thereto; future dividends and share buybacks; anticipated funds from operations and dividend growth over the next ten or more years; expectations of future funds from operations and free cash flow; expectations of future returns to shareholders; future requirements for additional capital and the reserves and resource estimates including OOIP; production estimates; costs and revenue; future demand for and prices of commodities; business prospects and opportunities; future application and advancements of EOR schemes and other secondary and tertiary recovery methods to improve recovery factors on the Royalty Properties; expectations of advancements of current and future CCUS projects and partnerships on PrairieSky’s Fee Lands, including CCUS; future opportunities for natural gas; expectations of advancements of current and future projects such as blue hydrogen, in situ resource gasification, dedicated CCUS and CCS projects, helium projects and other mineral projects; expectations regarding downspacing and infill drilling; expectations on timing to repay bank debt; expectations regarding continued improvement in technology and application of new drilling and completion techniques, including application of horizontal drilling in areas otherwise largely delineated with vertical wells; expectation that development using multilaterals where multiple zones exist could add significant unattributed upside in the Mannville Stack; potential future upside through future technology advancements in formations/areas that are unsuitable for multilateral drilling in the Mannville Stack; expectations regarding ongoing and continued activity levels on the Royalty Properties; estimated gross capital spent on the Royalty Properties and capital efficiencies related thereto, and future capital spend on the Royalty Properties; expectations regarding infill drilling and future development of the Lindbergh SAGD Project and the Onion Lake SAGD Project, including timing thereof and production rates therefrom; future upside in the potential development of smaller scale SAGD projects; expectations regarding new discoveries and the contribution to the reserves, production and financial results of the Company; expectations regarding optimization efforts on certain plays, including shallow natural gas plays, and the resulting effect on declines in production; expectation that improvements in natural gas pricing could result in additional capital on natural gas plays; PrairieSky’s ability to lease large amounts of land, and its corresponding ability to attract associated bonus consideration revenues and capital spent on the Royalty Properties; expectations that data from drilling activities will lead to exploitation of additional zones and substances that were not otherwise targeted; estimates regarding deductions and transportation and processing costs in certain play areas and processing and transportation capacity in the future; PrairieSky’s intention to farmout certain Crown Interest Lands in exchange for a GORR Interest; expectations regarding the future development on the Company’s Clearwater, Duvernay and Mannville Stack land positions, including expectations that they will add incremental growth to royalty production and value over time; continued expansions of Clearwater waterflood support; the expectation that the advancement of drilling techniques and innovation may result in new pool discoveries, incremental future locations and additional capital which may add significant value in the future; future potential optionality on the Royalty Properties; and the prospectivity of lands that are not included in the play reviews included in this Investor Day Presentation and the Company’s expectations regarding the same. In addition, statements (including data in tables) relating to reserves and resources, including OOIP, are forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, and no assurance can be given that the estimates and assumptions are accurate and that such reserves and resources will be realized. Such forward-looking statements reflect management’s current beliefs and are based on information currently available to management. All information other than information of historical fact is forward-looking information. Often, but not always, forward-looking statements can be identified by the use of words such as "plans", "expects", "is expected", "budgets", "potential", "scheduled", "estimates", "forecasts", "predicts", "projects", "intends", "targets", "aims", "anticipates", "contemplates", "continues", "proposes", "pursue" or "believes" or variations (including negative variations) of such words and phrases or may be identified by statements to the effect that certain actions "may", "could", "should", "would", "might” or "will" be taken, occur or be achieved. Forward-looking statements involve known and unknown risks, uncertainties and other factors, which may cause the actual results, performance or achievements of PrairieSky to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. A number of factors could cause actual events or results to differ materially from any forward-looking statement, including, without limitation: fluctuations in the prices of crude oil, natural gas and NGL that drive royalty revenue; changes in national, provincial and local government legislation and regulations, including permitting and licensing regimes and taxation policies and the enforcement thereof; regulatory and political or economic developments in any of the jurisdictions where properties in which PrairieSky holds a royalty interest are located; tariffs or other restrictive trade measures or countermeasures affecting trade between Canada and the United States; risks related to the operators of the properties in which PrairieSky holds a royalty interest, including changes in the ownership and control of such operators; influence of macroeconomic developments; business opportunities that become available to, or are pursued by PrairieSky; reduced access to debt and equity capital; litigation; title, permit or license disputes related to interests on any of the properties in which PrairieSky holds a royalty interest; excessive cost escalation as well as development, permitting, infrastructure, operating or technical difficulties on any of the properties in which PrairieSky holds a royalty interest; actual hydrocarbon content may differ materially from the reserves and resource estimates contained in technical reports; rate and timing of production differences from resource estimates and other technical reports; risks and hazards associated with the business of exploration and development on any of the properties in which PrairieSky holds a royalty interest, including, but not limited to unusual or unexpected geological conditions, natural disasters, terrorism, civil unrest or a political change; and the integration of acquired assets. The statements contained in this Investor Day Presentation are based upon assumptions management believes to be reasonable, including, without limitation: the ongoing operation of the properties in which PrairieSky holds a royalty interest by the owners or operators of such properties in a manner consistent with good oilfield practices and all applicable regulations; the availability of capital to such operations to further develop such properties; the accuracy of public statements and disclosures made by the operators on the Royalty Properties; no material adverse change in the market price of the commodities that underlie the asset portfolio; no material changes to existing tax treatment; no adverse development in respect of any significant property in which PrairieSky holds a royalty interest; the accuracy of publicly disclosed expectations for the development of underlying properties that are not yet in production integration of acquired assets; the accuracy of assumptions and information used in PrairieSky’s internal assessments of its Royalty Properties and the prospectivity thereof, including with respect to acquired assets; and the absence of any other factors that could cause actions, events or results to differ from those anticipated, estimated or intended. However, there can be no assurance that forward looking statements will prove to be accurate, as actual results and future events could differ materially from those anticipated in such statements and investors are cautioned that forward looking statements are not guarantees of future performance. PrairieSky cannot assure investors that actual results will be consistent with these forward-looking statements. Accordingly, investors should not place undue reliance on forward looking statements due to the inherent uncertainty therein. For additional information with respect to risks, uncertainties and assumptions, please refer to the "Risk Factors" section of our most recent AIF filed with the Canadian securities regulatory authorities available at www.sedar.com and on our website at www.prairiesky.com. The forward-looking statements herein are made as of March 31, 2025 only and are expressly qualified in their entirety by this cautionary statement. PrairieSky does not assume any obligation to update or revise them to reflect new information, estimates or opinions, future events or results or otherwise, except as required by applicable law. This Investor Presentation does not constitute an offer to sell or a solicitation for an offer to purchase any security in any jurisdiction.
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Disclaimer & Cautionary Statements 116 Cautionary Statement Regarding Future-Oriented Financial Information This Investor Day Presentation also contains future-oriented financial information and financial outlook information (collectively, "FOFI") about our prospective results, funds from operations, future development of the Royalty Properties, future drilling locations, future reserve additions and in each case values associated therewith, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth above. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on FOFI and forward-looking statements. PrairieSky’s actual results, performance, realization or achievement of anticipated values could differ materially from those expressed in, or implied by, these forward-looking statements and FOFI, or if any of them do so, what benefits PrairieSky will derive therefrom. PrairieSky has included the forward-looking statements and FOFI in this Investor Day Presentation in order to provide readers with a more complete perspective on PrairieSky’s future value proposition and future development potential and such information may not be appropriate for other purposes. PrairieSky disclaims any intention or obligation to update or revise any forward-looking statements or FOFI, whether as a result of new information, future events or otherwise, except as required by law. Cautionary Statement Regarding Presentation of Oil and Natural Gas Reserves, Production Information and Acreage Information This Investor Day Presentation contains information relating to crude oil, natural gas and NGL and other information prepared in accordance with the requirements of Canadian securities laws in effect in Canada. Reference should be made to the reserves and other information with respect to the Royalty Properties in the AIF which has been prepared and are presented in accordance with NI 51-101 - Standards of Disclosure for Oil and Gas Activities. See "Reserves and Other Oil and Gas Information – Notes and Definitions" in the AIF for additional information. All acreage information with respect to the Fee Lands, GRT Lands, Crown Interest Lands and GORR Lands in this Investor Day Presentation has been presented on a gross acre basis. For the Fee Lands, gross acres refers to the total percentage undivided interest acres in which the Company holds fee simple mineral title and the associated mines and minerals rights. For the GRT Lands and GORR Lands, gross acres refers to the total acres related to the leasehold or title interests held by a third party in the lands on which the Company holds the GRT Interests or GORR Interests (each as defined herein). Gross acres for the GRT Lands or GORR Lands do not account for the Company’s net GRT or GORR percentage royalty ownership interest held in such lands. Gross acreage for Crown Interest Lands is the acres covered by the lease and the net acres are the Company’s ownership share of the gross acres. The presentation of gross acres for the Fee Lands, GRT Lands and GORR Lands is consistent with the presentation by certain of the Company’s peers that hold a royalty interest on lands leased to or by third parties. All references in this Investor Day Presentation to working interest means the rights granted to a lessee of a property to explore for and produce petroleum and/ or natural gas on the leased lands, upon which such lessee bears the operating costs, capital costs, environmental liabilities or reclamation obligations associated with petroleum and natural gas development. Readers are strongly advised to refer to the detailed reserves and other information contained in the AIF starting on page 18 under the heading “Reserves Data and Other Oil and Gas Information”, and the cautionary statements under the heading “Advisories” commencing on page 3 of the AIF. OOIP estimates and recovery rates are as at December 31, 2024 and are based on current accepted technology.
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117 Non-GAAP Measures and Ratios Certain measures and ratios in this presentation do not have any standardized meaning as prescribed by IFRS and therefore, are considered non-GAAP measures and ratios. These measures and ratios may not be comparable to those presented by other issuers. These measures and ratios are commonly used in the oil and gas industry and by the Company to provide potential investors with additional information regarding the Company’s ability to generate funds from its operations. This presentation includes the following non-GAAP measures and ratios: 1) Royalty Operating Margin is calculated by subtracting production and mineral tax expense from royalty production revenue. This amount is then divided by royalty production revenue in the period to generate a cash margin as a percentage. 2) Royalty Operating Margin per BOE which is PrairieSky’s royalty production revenue less production and mineral expense. This amount is then divided by the average production in the period to generate a cash margin per unit sold. This measure is used to demonstrate the comparability between the operations of PrairieSky and production and exploration companies. 3) Royalty Operating Margin as a % of Revenue which is the royalty operating margin divided by total royalty production revenue shown as a percentage to demonstrate comparability between the operations of PrairieSky and production and exploration companies. Below is a summary of the calculation of each of the above measures: 4) EBITDA used on page 3, 4 and 106 of this Corporate Presentation is net earnings adjusted for non-cash items, interest expense and income taxes as defined in PrairieSky’s credit facility. See page 12 of PrairieSky’s Management’s Discussion and Analysis for the three months ended March 31, 2025 and 2024 under the section Bank Debt and page 15 of PrairieSky’s Management’s Discussion and Analysis for the year ended December 31, 2024 and 2023 under the section Bank Debt. Both sections are incorporated by reference into this Corporate Presentation. $millions (except per BOE amounts) Three months ended March 31, 2025 Three months ended March 31, 2024 Royalty production revenue $119.9 $113.2 Production and mineral expenses 1.3 1.3 Royalty operating margin $118.6 $111.9 Royalty operating margin per BOE $52.01 $47.24 Royalty operating margin as a % of Revenue 99% 99%
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Non-GAAP Measures and Ratios 118 5) Cash G&A is defined as cash administrative expenses in PrairieSky’s Management’s Discussion and Analysis for the year ended December 31, 2024 and 2023 on pages 10 under the sections Administrative Expenses and Non-GAAP Measures and Ratios section starting on page 27. Cash administrative expenses represents administrative expenses excluding the volatility and fluctuations in non-cash share-based compensation expense. Both sections are incorporated by reference into this Corporate Presentation. A reconciliation of cash administrative expense for years ended December 31, 2022 and 2021 can be found in PrairieSky’s Management’s Discussion and Analysis under the Section Non-GAAP Measures and Ratios starting on page 26. A reconciliation of cash administrative expense for years ended December 31, 2020 and 2019 can be found in PrairieSky’s Management’s Discussion and Analysis under the Section Non-GAAP Measures and Ratios starting on page 26. A reconciliation of cash administrative expense for years ended December 31, 2018 and 2017 can be found in PrairieSky’s Management’s Discussion and Analysis under the Section Non-GAAP Measures and Ratios starting on page 24. Each of these sections have been incorporated by reference into this Corporate Presentation. Cash G&A or cash administrative expense calculations for prior years (2014-2016) have been performed in a consistent manner. Below is a reconciliation from administrative expenses to cash administrative expenses. 6) Cash G&A per BOE is calculated by dividing cash administrative expenses by the average daily production volumes sold for the period. Cash G&A per BOE or cash administrative expense per BOE assists management and investors in evaluating operating performance on a comparable basis between periods. 7) Dividend payout ratio is calculated as dividends declared as a percentage of funds from operations. Dividend payout ratio is used by dividend paying companies to assess dividend levels in relation to the funds generated and used in operating activities. Dividend payout ratio is defined in the Company's Management’s Discussion and Analysis for the three months ended March 31, 2025 and 2024 (under the section "Non- GAAP Measures and Ratios" starting at page 21) which sections are incorporated by reference in this Corporate Presentation. Below is a summary of the dividend payout ratio calculation: $millions (except per BOE amounts) Year ended Dec. 31, 2024 Year ended Dec. 31, 2023 Year ended Dec. 31, 2022 Year ended Dec. 31, 2021 Year ended Dec. 31, 2020 Year ended Dec. 31, 2019 Year ended Dec. 31, 2018 Year ended Dec. 31, 2017 Year ended Dec. 31, 2016 Year ended Dec. 31, 2015 Period ended Dec. 31, 2014 Total administrative expenses 47.0 45.0 48.8 32.0 18.6 23.7 20.0 31.1 32.2 27.1 16.0 Share-based compensation expense (21.2) (20.9) (28.3) (12.5) (2.3) (4.6) 1.3 (9.8) (10.2) (4.7) (2.7) Cash payments made – share unit plans 13.7 23.8 5.0 0.7 1.7 2.2 5.1 6.4 1.7 1.0 - Total cash administrative expenses 39.5 47.9 25.5 20.2 18.0 21.3 26.4 27.7 23.7 23.4 13.3 $millions (except per BOE amounts) Three months ended March 31, 2025 Three months ended March 31, 2024 Funds from 0perations 85.8 83.0 Dividends declared 61.2 59.7 Dividend payout ratio 71% 72%
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Non-GAAP Measures and Ratios 119 Supplementary Financial Measures 8) Enterprise value (EV) is a supplementary financial measure and is calculated as market capitalization plus net debt. It is a useful measure of the market value of a Company's debt and equity. 9) EV/EBITDA ratio measures a company’s enterprise value to its earnings before interest, taxes, depreciation and amortization (EBITDA) and is used to assess a company’s valuation compared to other companies. 10) D/EBITDA (debt/EBITDA) is a financial ratio that measures a company’s ability to cover its debt obligations through its operating earnings. 11) Rate of return metrics provide investors with comparable measures between companies and to demonstrate the sustainability of the business model: "Return on Equity" ("ROE") is net earnings divided by average shareholders’ equity. "Return on Capital Employed" ("ROCE") is net earnings before interest and taxes divided by average total assets less average current liabilities. PrairieSky has provided Adjusted ROE and CROCE metrics to provide further comparability between PrairieSky’s returns removing non-cash expenses including DD&A. "Adjusted Return on Equity" ("AdjROE") is funds from operations divided by average shareholders’ equity. "Cash Return on Capital Employed" ("CROCE") is funds from operations divided by average total assets less average current liabilities. Further information on non-GAAP measures and ratios can be found in PrairieSky Royalty’s Management Discussion & Analysis and Interim Condensed Consolidated Financial Statements and notes thereto for the three months ended March 31, 2025 and 2024, which are available on SEDAR+ at www.sedarplus.com or PrairieSky Royalty’s website at www.prairiesky.com.
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Other Disclosure CONVERSIONS OF NATURALGAS TO BOE To provide a single unit of production for analytical purposes, natural gas production and reserves volumes are converted mathematically to equivalent barrels of oil (boe). We use the industry-accepted standard conversion of six thousand cubic feet of natural gas to one barrel of oil (6 Mcf = 1 bbl). The 6:1 boe ratio is based on an energy equivalency conversion method primarily applicable at the burner tip. It does not represent a value equivalency at the wellhead and is not based on either energy content or current prices. While the boe ratio is useful for comparative measures and observing trends, it does not accurately reflect individual product values and might be misleading, particularly if used in isolation. As well, given that the value ratio, based on the current price of crude oil to natural gas, is significantly different from the 6:1 energy equivalency ratio, using a 6:1 conversion ratio may be misleading as an indication of value. CURRENCY AND REFERENCES TO PRAIRIESKY ROYALTY All information included in this presentation is shown on a Canadian dollar basis. For convenience, references in this document to the “Company”, “we”, “us”, “our”, and “its” may, where applicable, refer only to PrairieSky Royalty Ltd. 120
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CONTACT INFORMATION PRAIRIESKY ROYALTY LTD. 1700,350 – 7 Avenue SW Calgary, AB T2P 3N9 T 587.293.4000 E Investor.relations@prairiesky.com PRAIRIESKY.COM