ARC Resources : Financial Report (2025aif)

About this update from Arc Resources Ltd.

2025 Annual Information Form March 5, 2026 TABLE OF CONTENTS GLOSSARY OF TERMS 3 SPECIAL NOTES TO READER 4 Regarding Forward-looking Information 4 Access to Documents 5 Abbreviations and Conversions 6 CORPORATE STRUCTURE 7 DEVELOPMENT OF OUR BUSINESS 7 General 7 Strategy 7 Three-Year History 8 DESCRIPTION OF OUR BUSINESS 11 General 11 Risk Factors 16 STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION 17 Disclosure of Reserves Data 17 Forecast Prices and Costs 19 Definitions and Notes to Reserves Data Tables 19 Reconciliations of Changes in Reserves 21 Future Development Costs 23 Undeveloped Reserves 23 Significant Factors or Uncertainties Affecting Reserves Data 25 Further Information Respecting Abandonment Obligations 25 Core Operating Areas 26 Crude Oil and Natural Gas Wells 26 Properties with No Attributed Reserves 27 Forward Contracts and Transportation Commitments 27 Tax Horizon 28 Costs Incurred 29 Exploration and Development Activities 29 Production Estimates 29 Production History 30 DIVIDENDS 31 Dividend Policy 31 Dividend History 31 CAPITAL STRUCTURE 32 Common Shares 32 Preferred Shares 32 Normal Course Issuer Bid 32 Borrowing 33 Credit Ratings 33 MARKET FOR SECURITIES 34 DIRECTORS AND EXECUTIVE OFFICERS 35 Directors 35 Executive Officers 36 Membership of Board Committees 37 Officer Biographies 37 Conflicts of Interest 40 AUDIT COMMITTEE DISCLOSURES............................................................................................................................................... 40 Members of the Audit Committee....................................................................................................................................................... 40 Principal Accountant Fees and Services............................................................................................................................................ 42 INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS.......................................................................... 42 TRANSFER AGENT AND REGISTRAR........................................................................................................................................... 42 MATERIAL CONTRACTS................................................................................................................................................................. 42 INTEREST OF EXPERTS.................................................................................................................................................................. 42 NON-GAAP AND OTHER FINANCIAL MEASURES........................................................................................................................ 43 ADDITIONAL INFORMATION........................................................................................................................................................... 43 APPENDIX A - REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR............................ A-1 APPENDIX B - REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION............ B-1 APPENDIX C - MANDATE OF THE AUDIT COMMITTEE................................................................................................................ C-1 GLOSSARY OF TERMS In this Annual Information Form, capitalized terms shall have the meanings set forth below: ARC Resources, ARC, We, Us, Our, Company, Corporation means ARC Resources Ltd., a corporation formed by amalgamation under the Business Corporations Act (Alberta), and all its controlled entities as a consolidated body at the applicable time; COGE Handbook means the Canadian Oil and Gas Evaluation Handbook maintained by the Society of Petroleum Evaluation Engineers (Calgary chapter), as amended from time to time; ESG means environmental, social, and governance; GLJ means GLJ Ltd., independent qualified reserves evaluator of Calgary, Alberta; GLJ Report means the report prepared by GLJ and dated February 3, 2026, evaluating the reserves attributed to ARC's assets as at December 31, 2025; IFRS Accounting Standards means International Financial Reporting Standards as issued by the International Accounting Standards Board; LNG means liquefied natural gas; Montney means our land bases across the Montney fairway in northeast British Columbia comprised of the Greater Dawson, Sunrise, Septimus, Sundown, Attachie, and Red Creek areas and in northern Alberta in the Kakwa and Ante Creek areas; NCIB means normal course issuer bid; NGLs means natural gas liquids; NI 51-101 means National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ; NI 51-102 means National Instrument 51-102 Continuous Disclosure Obligations ; Shareholders means holders of common shares of ARC Resources; Tax Act means the Income Tax Act (Canada); Three Consultant Average means the average price forecast from three independent qualified reserves evaluators, GLJ, Sproule ERCE, and McDaniel & Associates Consultants Ltd., of Calgary, Alberta; TSX means the Toronto Stock Exchange; and U.S. means the United States. Certain other terms used in this Annual Information Form but not defined herein are defined in NI 51-101 and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101. SPECIAL NOTES TO READER Regarding Forward-looking Information Certain information and statements contained in this Annual Information Form, and in certain documents incorporated by reference into this Annual Information Form, constitute forward-looking information under Canadian securities laws. This information relates to future events or our expected future performance. All information other than statements or information of historical fact may be forward-looking information. Forward-looking information is often, but not always, identified by the use of words such as "seek," "anticipate," "budget," "plan," "continue," "estimate," "expect," "forecast," "may," "will," "project," "predict," "potential," "target," "intend," "could," "might," "should," "believe," and similar expressions. In addition, there is forward-looking information in this Annual Information Form under the headings: " Strategy" as to the expectation that commencing in 2027, end-market diversification will include international price exposure through its long-term agreements to supply natural gas to North American LNG projects; " Three-Year History" as to the terms and timing of the long-term liquefaction tolling services agreement with Cedar LNG (as defined herein), as to the timing of the commencement of the second long-term natural gas supply agreement with Cheniere Energy, Inc., as to the expectation that the lands, subject to the earning and development with Tsaa Dunne Za Energy Limited Partnership, upon development, will increase ARC's Attachie position by greater than 10 per cent, and as to the timing of the commencement of the long-term sale and purchase agreement with ExxonMobil LNG Asia Pacific for the supply of LNG; " Marketing and Risk Management" as to ARC's goals with respect to international price exposure; " Statement of Reserves Data and Other Oil and Gas Information " as to our reserves and future net revenues from our reserves, pricing and inflation rates, and future development costs, including expected sources of capital for such costs; as to the development of our proved undeveloped reserves and probable undeveloped reserves; and as to our future development activities, forward contracts and transportation commitments, abandonment and reclamation obligations, tax horizon, exploration and development activities, expected sources of funding, and production estimates; " Dividends" as to the payment of future dividends; and "Capital Structure" as to future financing flexibility from preferred shares and ARC's intention that the issuance of any preferred shares will not, without shareholder approval, be issued for any anti-takeover purposes. This information involves known and unknown risks, uncertainties, and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information. We believe the expectations reflected in this forward-looking information are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking information included in, or incorporated by reference into, this Annual Information Form should not be unduly relied upon. This information speaks only to estimates as of the date of this Annual Information Form or as of the date specified in the documents incorporated by reference into this Annual Information Form, as the case may be. In addition to the forward-looking information identified above, this Annual Information Form, and the documents incorporated by reference, contain forward-looking information pertaining to the performance characteristics of our crude oil and natural gas assets; crude oil and natural gas production levels; the size of the crude oil and natural gas reserves; expectations regarding the effect of laws and regulations on ARC; projections of market prices and costs; treatment under governmental regulatory regimes, including costs of compliance and non-compliance and tax laws; potential impacts of changes to the project approval process; impacts of current commodity prices on the Company, including with respect to abandonment and reclamation obligations; budget expectations; expectations with respect to making customary payments to credit rating organizations; expectations that ARC's dividends will be classified as "eligible dividends" under the Tax Act ; and capital expenditure programs. Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. In addition, these risks and uncertainties are material factors affecting the success of our business. Such factors include, but are not limited to: declines in crude oil and natural gas prices; various pipeline constraints; potential natural gas curtailments due to low natural gas prices; the payment of dividends, if any; variations in interest rates and foreign exchange rates; stock market volatility; uncertainties relating to market valuations; refinancing risk for existing debt and debt service costs; access to external sources of capital; risks associated with our risk management activities; third-party credit risk; risks relating to a changing investor sentiment; asset concentration; risks relating to information technology systems and cyber security; risks associated with the exploitation of our assets and our ability to acquire reserves; ARC's ability to successfully close, integrate and realize the anticipated benefits of completed, contemplated, or future acquisitions and divestitures; access to sufficient capital to pursue any development plans; government regulation, policy and control and changes in government legislation; the impacts of the ongoing Middle-East conflicts, Russia-Ukraine war and geopolitical developments in Venezuela (and any associated sanctions) on the global economy and commodity prices; changes in income tax laws, royalty rates, and other incentive programs; uncertainties associated with estimating crude oil and natural gas reserves; risks associated with acquiring, developing, and exploring for crude oil and natural gas and other aspects of our operations; our reliance on hydraulic fracturing; risks associated with large projects or expansion of our activities; the failure to realize anticipated benefits of acquisitions and dispositions or to manage growth; changes in climate change laws and other environmental regulations; competition in the crude oil and natural gas industry for, among other things, acquisitions of reserves, undeveloped lands, skilled personnel, and drilling and related equipment; risks of non-cash losses as a result of the application of accounting policies; our operating activities and ability to retain key personnel; depletion of our reserves; risks associated with securing and maintaining title to our assets; ARC's ability to repurchase its securities under the NCIB; risks for United States ("U.S.") and other non-resident shareholders; risks described in the section entitled " Risk Factors " contained within ARC's Management Discussion and Analysis dated February 5, 2026 (the "MD&A"), available on ARC's website at www.arcresources.com and on SEDAR+ at www.sedarplus.ca ; and other factors, many of which are beyond our control. The actual results could differ materially from those results anticipated in this forward-looking information, which are based on assumptions, including as to the market prices for crude oil and natural gas; the continuation of the present policies of the Board of Directors relating to management of ARC, and the payment of dividends, capital expenditures and other matters; the factors and assumptions under the heading " Significant Factors or Uncertainties Affecting Reserves Data" ; the continued availability of capital and skilled personnel, acquisitions of reserves and undeveloped lands; anticipated abandonment and reclamation costs; the continuation of the current tax, royalty, tariff and regulatory regime, and other assumptions contained in this Annual Information Form. Statements relating to "reserves" are deemed to be forward-looking information, as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can be profitably produced in the future. Statements pertaining to dividend increases and the repurchase of ARC's outstanding common shares, while based on ARC's current intentions and beliefs, are not guaranteed and should not be unduly relied upon. Any decisions with respect to dividends and/or share repurchases are subject to the approval of the Board of Directors of ARC. Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward-looking information contained in this Annual Information Form and the documents incorporated by reference herein are expressly qualified by this cautionary statement. We do not undertake any obligation to publicly update or revise any forward-looking information except as required by securities laws or regulations. ARC's audited consolidated financial statements (the "financial statements") as at and for the year ended December 31, 2025, and MD&A are available on ARC's website at www.arcresources.com and on SEDAR+ at www.sedarplus.ca . The disclosure under the section entitled " Non-GAAP and Other Financial Measures " contained in ARC's MD&A is incorporated by reference into this document. Also refer to the section entitled " Non-GAAP and Other Financial Measures " contained within this Annual Information Form. Access to Documents Any document referred to in this Annual Information Form and described as being available on SEDAR+ at www.sedarplus.ca (including those documents referred to as being incorporated by reference in this Annual Information Form) may be obtained free of charge from us at [email protected] or at 1500, 308 - 4 th Avenue SW, Calgary, Alberta, T2P 0H7. Abbreviations and Conversions Crude Oil and Natural Gas Liquids bbl barrel bbl/d barrels per day Mbbl thousand barrels MMbbl million barrels API indication of specific gravity of crude oil measured on the American Petroleum Institute ("API") gravity scale Natural Gas Mcf thousand cubic feet Mcf/d thousand cubic feet per day MMcf million cubic feet MMcf/d million cubic feet per day Bcf billion cubic feet Bcf/d billion cubic feet per day Bcfe billion cubic feet equivalent Tcf trillion cubic feet MMBtu million British thermal units MMBtu/d million British thermal units per day GJ gigajoules Other boe barrels of oil equivalent boe/d barrels of oil equivalent per day Mboe thousand barrels of oil equivalent MMboe million barrels of oil equivalent $M thousand dollars $MM million dollars We have adopted the standard of 6 Mcf:1 bbl when converting natural gas to boe. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of six Mcf per 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. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value. All dollar amounts set forth in this Annual Information Form are in Canadian dollars, except where otherwise indicated. The following table sets forth certain standard conversions between Standard Imperial Units and the International System of Units (or metric units), in accordance with the COGE Handbook. To Convert From To Multiply By cubic metres cubic feet 35.49373 cubic feet cubic metres 0.0282 barrels cubic metres 0.15898 cubic metres barrels 6.2901 feet metres 0.3048 metres feet 3.28084 CORPORATE STRUCTURE ARC was originally founded in 1996 as a conventional crude oil and natural gas royalty trust. On January 1, 2011, the Corporation was formed by amalgamation under the Business Corporations Act (Alberta). Our principal office is located at 1500, 308 - 4 th Avenue SW, Calgary, Alberta, T2P 0H7 and our registered office is located at 2400, 525 - 8 th Avenue SW, Calgary, Alberta, T2P 1G1. The following diagram illustrates the intercorporate relationship between ARC and its subsidiaries, the percentage of votes attached to all voting securities of the subsidiaries beneficially owned, controlled or directed, directly or indirectly, by ARC and the jurisdiction of incorporation of the subsidiaries. DEVELOPMENT OF OUR BUSINESS General ARC is a leading Canadian energy company, Canada's largest condensate producer and one of the country's largest natural gas producers. ARC's business activities include the exploration, development, and production of crude oil, condensate, natural gas, and NGLs in Alberta and British Columbia, Canada. ARC has focused on the acquisition and development of resource-rich properties that provide for both near-term and long-term growth. ARC trades on the TSX under the symbol ARX and currently pays a quarterly dividend to its shareholders. Strategy ARC's vision is to be recognized as a "Best-in-Class Responsible Energy Producer". The strategy to achieve this is built upon four pillars that are foundational to the organization: high-quality assets and operational excellence, commercial activities and risk management, financial sustainability and return on investment, and people and ESG leadership. These pillars have created a strong foundation for excellent business performance, measured by delivering superior risk-adjusted returns that are sustainable through commodity price cycles. ARC's competitive advantage is anchored by its scale in world-class assets. Over its history, ARC has amassed greater than one million acres in the heart of the liquids-rich areas of the Montney formation, providing an inventory of high-quality development opportunities that extends for decades. Superior margins are achieved through strong price realizations enabled by ARC's market diversification and low-cost structure. The Company's owned-and-operated infrastructure, long-term transportation agreements, and commitment to operational excellence underpin its low-cost structure. Through its access to key North American end-markets, the Company has consistently achieved strong price realizations that have historically outperformed local benchmarks. Commencing in 2027, end-market diversification will include international price exposure through its long-term agreements to supply natural gas to North American LNG projects. ARC is committed to balancing organic investment with a meaningful return of capital to deliver an optimal total return for its shareholders. ARC's preferred method to return capital is through a growing base dividend and share repurchases. Three-Year History The following is a description of the general development of our business over the last three financial years and to the date of this Annual Information Form. 2023 Record annual average production of 351,954 boe/d. ARC delivered record average production of 351,954 boe/d in 2023, representing a 12 per cent per share increase relative to the prior year. The increase in production was primarily driven by increased natural gas production from new wells coming on-stream in the Sunrise and Kakwa areas. ARC's production by commodity type was 8,364 bbl/d of crude oil, 75,516 bbl/d of condensate, 47,760 bbl/d of NGLs, and 1,322 MMcf/d of natural gas in 2023. Advancement of LNG strategy. In 2023, ARC entered into a non-binding Memorandum of Understanding with Cedar LNG Partners LP. ("Cedar LNG") for an anticipated 20-year agreement to supply and liquefy approximately 200 MMcf/d of natural gas. ARC also announced that it entered into its second long-term natural gas supply agreement with Cheniere Energy, Inc. that is expected to commence in 2029. ARC will supply 140,000 MMBtu/d of natural gas and will receive a Title Transfer Facility index price less deductions for liquefaction, transport, and regasification. Record safety performance and record capital expenditures. Cash flow used in investing activities was $1.7 billion and capital expenditures (1) were a record $1.8 billion. Despite increased levels of capital and operational activity, 2023 was a record year in safety performance. ARC drilled 148 wells, completed 151 wells, and completed several infrastructure projects including the expansion of its Sunrise facility and the electrification of its Dawson Phase III and IV facilities. ARC also announced the sanctioning of its Attachie Phase I facility. Return on investment. Return on average capital employed ("ROACE") (1) was 23 per cent in 2023. Record year in reserves and net present value of proved plus probable reserves per share increased 13 per cent. Reserves across all categories were a record, increasing from the prior year by between 12 and 13 per cent per share on a proved producing, proved, and proved plus probable basis. ARC's before-tax net present value of proved plus probable reserves, discounted at 10 per cent, increased from the prior year to $38.47 (2) per share at December 31, 2023. The proved plus probable net present value considered the development of 20 per cent of ARC's internally identified inventory. Return of capital. ARC generated cash flow from operating activities of $2.4 billion ($3.92 per share) (1) and free funds flow (1) of $790 million ($1.29 per share) (1) in 2023 and distributed 110 per cent of free funds flow to shareholders. NCIB renewed. On August 30, 2023, ARC received TSX approval to renew its NCIB. The renewed NCIB allowed ARC to purchase up to 60.7 million of its outstanding common shares, representing 10 per cent of the Company's public float over a 12-month period, which commenced September 1, 2023. In 2023, ARC repurchased 25.3 million common shares at a weighted average price of $18.34 for a total cost of $464 million. 2024 Annual average production of 347,908 boe/d. ARC delivered full-year average production of 347,908 boe/d in 2024. In the fourth quarter of 2024, ARC achieved average production of 382,341 boe/d, the highest in its history. ARC's production by commodity type was 6,972 bbl/d of crude oil, 80,294 bbl/d of condensate, 42,787 bbl/d of NGLs, and 1,307 MMcf/d of natural gas in 2024. Commissioning of Attachie Phase I. ARC completed construction and successfully commissioned the first phase of its Attachie development in October 2024. Production from the Attachie Phase I facility increased throughout the fourth quarter to average approximately 29,000 boe/d in December, and included approximately 18,000 bbl/d of condensate and NGLs. Capital discipline and profitability. Natural gas production from ARC's Sunrise asset was deliberately curtailed due to low natural gas prices during the last half of 2024. The deliberate curtailments reduced ARC's full-year average production by approximately 10,500 boe/d. This decision allowed ARC to preserve resource for periods when natural gas prices were higher and defer a portion of capital. In alignment with ARC's commitment to long-term profitability, Sunrise production was restored in the fourth quarter as natural gas prices recovered. ARC executed its 2024 capital program safely and efficiently. Cash flow used in investing activities was $1.9 billion in 2024. ARC invested $1.85 billion in capital expenditures to drill 159 wells and complete 144 wells. As of December 31, 2024, net debt was $1.3 billion (1) or 0.5 times funds from operations (1) , consistent with the prior year. Continued advancement of LNG strategy. In 2024, ARC announced a long-term liquefaction tolling services agreement with Cedar LNG. Under this agreement, ARC is obligated to deliver approximately 200 MMcf per day of natural gas for liquefaction for a term of 20 years commencing with Cedar LNG's commercial operations, anticipated in late 2028. Record reserves across all categories in 2024. Proved producing and proved plus probable reserves each increased by five per cent compared to 2023. ARC's before-tax net present value of proved plus probable reserves, discounted at 10 per cent, increased six per cent from 2023 to $40.66 per share at December 31, 2024. ARC reported positive technical revisions in all three categories (proved producing, total proved, and proved plus probable) due to relative outperformance across several assets, most notably its Kakwa and Greater Dawson assets. Positive technical revisions and extensions represented a 28 per cent increase from 2023 proved producing reserves. NCIB renewed. On August 30, 2024, ARC received TSX approval to renew its NCIB. The renewed NCIB allowed ARC to purchase up to 59.4 million of its outstanding common shares, representing 10 per cent of the Company's public float over a 12-month period, which commenced September 6, 2024. In 2024, ARC repurchased 8.5 million common shares at a weighted average price of $23.81 for a total cost of $202 million. Return of capital. ARC generated cash flow from operating activities of $2.4 billion ($3.94 per share) and free funds flow of $627 million ($1.05 per share). For the second consecutive year, ARC returned essentially all of its free funds flow to shareholders through share repurchases and dividends. During the year, ARC declared dividends of $416 million and increased its quarterly dividend by 12 per cent from $0.17 per share to $0.19 per share. Additionally, ARC disposed of certain non-core, non-Montney assets for total cash proceeds of $80 million, which were allocated to share repurchases. Executive appointment. Effective February 8, 2024, Michael C. Capon was appointed to the position of Vice President, Information Technology. 2025 Record annual average production. ARC delivered record annual average production of 374,336 boe/d in 2025. In the fourth quarter, ARC achieved average production of 408,382 boe/d, the highest in its history. ARC's annual average production by commodity type was 8,322 bbl/d of crude oil, 98,662 bbl/d of condensate, 46,625 bbl/d of NGLs, and 1,324 MMcf/d of natural gas in 2025. Expansion of core Kakwa region. In July 2025, ARC completed an acquisition of condensate-rich Montney assets in the Kakwa region in Alberta (the "Kakwa Acquisition") in an all-cash transaction valued at approximately $1.6 billion (3) . Located directly adjacent to ARC's Kakwa development, these assets added approximately 35,000 to 40,000 boe/d of production, including approximately 11,000 bbl/d of condensate. The acquired assets are underpinned by a substantial drilling inventory, reinforcing ARC's position as Canada's largest Montney and condensate producer. Attachie Development Agreement with Tsaa Dunne Za Energy. ARC executed an agreement for the earning and development of up to 36 contiguous sections in the Montney with the Tsaa Dunne Za Energy Limited Partnership, a limited partnership owned by Halfway River First Nation. The lands, upon development, increase ARC's Attachie position by greater than 10 per cent to approximately 360 sections, and are directly adjacent to ARC's existing Attachie asset in the condensate-rich region of the Montney. Continued commitment to discipline and profitability. Natural gas production from ARC's Sunrise asset was deliberately curtailed during the last half of 2025, due to low natural gas prices. These curtailments reduced ARC's annual average production by approximately 12,000 boe/d (approximately 70 MMcf/d). This decision allowed ARC to preserve resource for periods when natural gas prices were higher and defer approximately $50 million of capital. When natural gas prices strengthened in the fourth quarter, Sunrise production was fully restored. Record safety performance during execution of the 2025 capital program. Cash flow used in investing activities was $3.5 billion in 2025, including the Kakwa Acquisition. ARC outperformed all safety targets while investing $1.9 billion in capital expenditures to drill 144 wells and complete 157 wells across its asset base. As at December 31, 2025, ARC's net debt balance was $2.9 billion, or 0.9 times funds from operations. Continued execution of LNG strategy. In March 2025, ARC announced a long-term sale and purchase agreement with ExxonMobil LNG Asia Pacific ("EMLAP"), an ExxonMobil affiliate, for the supply of LNG. Under the agreement, EMLAP will purchase ARC's LNG offtake from the Cedar LNG Project, approximately 1.5 million tonnes per annum at international pricing. The agreement commences with commercial operations at the Cedar LNG Facility, expected in late 2028. Record reserves across all categories in 2025. Proved developed producing and proved plus probable reserves increased by 15 per cent and nine per cent, respectively, compared to 2024. ARC's before-tax net present value of proved plus probable reserves of $22.1 billion, discounted at 10 per cent, equates to $38.71 per share. In 2025, ARC replaced 121 per cent of its proved plus probable reserves, marking the 18th consecutive year proved plus probable reserve replacement from development has been 120 per cent of produced reserves or greater. Proved plus probable reserves of 2,277 MMboe as at December 31, 2025, were a record, driven by the Kakwa Acquisition and organic reserve growth. NCIB renewed. On September 4, 2025, ARC received TSX approval to renew its NCIB. The renewed NCIB allows ARC to purchase up to 58 million of its outstanding common shares, representing 10 per cent of the Company's public float over a 12-month period, which commenced September 8, 2025. In 2025, ARC repurchased 19.7 million common shares at a weighted average price of $26.09 for a total cost of $514 million. Since commencing its initial NCIB in September 2021, ARC has repurchased approximately 22 per cent of its total outstanding shares, or 159 million common shares, at a weighted average price of $17.74 per share. Return of capital. In 2025, ARC generated cash flow from operating activities of $3.1 billion ($5.31 per share) and funds from operations of $3.2 billion ($5.48 per share), while free funds flow was $1.3 billion ($2.20 per share). ARC distributed 75 per cent of free funds flow to shareholders through its base dividend and share repurchases, with the remainder allocated to debt reduction. During the year, ARC declared dividends of $452 million and increased its quarterly dividend by 11 per cent from $0.19 per share to $0.21 per share. This is a specified financial measure. See " Non-GAAP and Other Financial Measures" contained within this AIF and in the MD&A for additional disclosure, which information is incorporated by reference, available on ARC's website at www.arcresources.com and on SEDAR+ at www.sedarplus.ca . This supplementary financial measure is comprised of the before-tax net present value for proved plus probable reserves, discounted at 10 per cent, as determined in accordance with NI 51-101, divided by common shares outstanding at the end of the period. The purchase price was approximately $1.6 billion for the Kakwa Acquisition before purchase price adjustments and unrelated equipment and land. DESCRIPTION OF OUR BUSINESS General The following describes certain general activities and conditions impacting our business. Revenue Sources and Royalties ARC's primary source of revenue is commodity sales from production, comprising sales of crude oil, condensate, NGLs, and natural gas. For further information refer to the section entitled " Commodity Sales From Production " contained within the MD&A, available on ARC's website at www.arcresources.com and on SEDAR+ at www.sedarplus.ca . ARC must pay royalties to the owners of the mineral rights of the lands on which ARC produces its products from, primarily the provincial governments of Alberta and British Columbia. Each province has legislation and regulation in place to govern Crown royalties and establish the royalty rates that crude oil and natural gas producers must pay in respect of the production of Crown resources. The royalty regime in a given province is in addition to applicable federal and provincial taxes and can be a significant factor in the profitability of crude oil, condensate, NGLs, and natural gas production. Royalties payable on production from lands where the Crown does not hold the mineral rights are negotiated between the freehold mineral owner and the lessee, though certain provincial taxes and other charges on production or revenue may still be payable. For further information on royalties paid by ARC refer to the section entitled " Royalties " contained within the MD&A, available on ARC's website at www.arcresources.com and on SEDAR+ at www.sedarplus.ca . Marketing and Risk Management ARC sells its production pursuant to fixed and variable-priced contracts. The transaction price for variable-priced contracts is based on the commodity price, adjusted for quality, location, or other factors, whereby each component of the pricing formula can be either fixed or variable, depending on the contract terms. Under these contracts, the Company is required to deliver a fixed volume of crude oil, natural gas, condensate, or NGLs to the contract counterparty. ARC's marketing strategy centers on accessing global demand markets at the lowest cost by focusing on a multi-prong approach of (i) accessing diversified markets and transporting commodities to key consuming regions, (ii) securing long-term transportation arrangements and managing risk through dual-connected facilities, and (iii) increasing revenues through margin expansion opportunities. For example, ARC's natural gas sales are physically diversified to multiple sales points within North America, each with different index-based pricing. ARC also has longterm natural gas sales contracts that are linked to international pricing. For further information refer to Note 17 " Financial Instruments and Market Risk Management" in the financial statements and the section entitled " Risk Management Contracts" contained within the MD&A, available on ARC's website at www.arcresources.com and on SEDAR+ at www.sedarplus.ca . In 2025, ARC entered into a long-term LNG sale and purchase agreement to align with a previously executed liquefaction tolling services agreement. For further information refer to the section entitled "Commodity Sales from Production" contained within the MD&A, available on ARC's website at www.arcresources.com and on SEDAR+ at www.sedarplus.ca . By 2029, approximately 25 per cent of ARC's anticipated natural gas production will be linked to international pricing. To support its marketing strategy, ARC enters into firm transportation service commitments in order to secure diversified market access for both its current production, as well as anticipated production from facility infrastructure planned to be operational in the future. For further information on ARC's transportation commitments refer to the section entitled " Contractual Obligations and Commitments" contained within the MD&A, available on ARC's website at www.arcresources.com and on SEDAR+ at www.sedarplus.ca . ARC's financial results are largely dependent on commodity prices received for its crude oil, condensate, natural gas, and NGLs production. To manage exposure to fluctuations in commodity prices, ARC utilizes a variety of risk management contracts. A summary of our financial contracts in respect of hedging activities can be found in Note 17 " Financial Instruments and Market Risk Management" in the financial statements and in the section entitled " Risk Management Contracts" contained within the MD&A, available on ARC's website at www.arcresources.com and on SEDAR+ at www.sedarplus.ca . As part of its physical risk management strategy, ARC owns and operates a network of facility infrastructure, with capacity to process approximately 2.0 Bcf/d of natural gas and handle approximately 200,000 bbl/d of crude oil, condensate, and NGLs. Competition The crude oil and natural gas industry is competitive in all of its phases. ARC competes with numerous other companies in the acquisition, exploration, development, production, transportation, and marketing of crude oil, condensate, NGLs, and natural gas and procuring timely and cost-effective services to carry out its operations. We also compete for skilled personnel. To a lesser extent, we also face competition from companies that supply alternative sources of energy, such as wind or solar power. The timing of when, and the degree to which, global energy markets transition from carbon-based sources to alternative energy sources is highly uncertain. Seasonal Factors Generally, the demand for natural gas increases during the winter months and decreases during the summer months. Seasonal anomalies such as mild winters or hot summers may impact general seasonal changes in natural gas demand. As well, the production of crude oil and natural gas can be dependent on access to geographic areas where development of reserves is to be conducted. Seasonal weather variations can affect access and operations in certain circumstances. Employees and Specialized Skill and Knowledge The operations and management of ARC requires the recruitment and retention of a skilled workforce, including engineers, geologists, geophysicists, finance, marketing, and human resource professionals and other key personnel required to find, acquire, develop and operate our assets, and transport and market our crude oil, condensate, NGLs and natural gas production. At December 31, 2025, ARC had 711 permanent professional, technical, and support staff, with 374 employees located in its Calgary office and 337 employees located across ARC's operating areas. Regulation The crude oil and natural gas industry in the provinces of British Columbia and Alberta is extensively regulated at the federal, provincial, and municipal levels. Regulations affecting elements of the energy sector in these jurisdictions are under constant review for amendment or expansion and frequently more stringent requirements are imposed. Various federal and provincial agencies, including the Alberta Energy Regulator, the British Columbia Energy Regulator, and the Canada Energy Regulator have, or may have in the future, legal and regulatory authority and oversight over ARC's exploration and development activities and operations. In addition, regulations imposed in other jurisdictions may influence the adoption of regulations in jurisdictions where ARC has operations. Environmental regulation is the responsibility of both the federal and provincial governments. While provincial governments and their delegates are responsible for most environmental regulation, the federal government can regulate environmental matters where there is impact to matters of federal jurisdiction or when they arise from projects that are subject to federal jurisdiction, such as interprovincial transportation undertakings, including pipelines and railways, and activities carried out on federal lands. Most recently, on November 27, 2025, the Governments of Canada and Alberta signed a Memorandum of Understanding (the "MOU") to collaborate on supporting the development of crude oil and natural gas resources, renewable energy, critical minerals, and other resource sectors in Western Canada. The primary tenet of the MOU is that the federal government will not implement the previously proposed Oil and Gas Sector Greenhouse Gas Emissions Cap Regulations (the "Oil and Gas Emissions Cap"), refer to the section entitled " Climate Change and Greenhouse Gas Emissions " below. Other features of the MOU include the pledge of both levels of government to design and commit to sector-specific stringency factors for large Alberta emitters under Alberta's Technology Innovation and Emissions Reduction Regulation (the "TIER Regulation"), and the continuation of annual carbon tax rate increases up to $130 per tonne. Ensuring compliance with the rules, regulations, and orders promulgated by such regulatory entities requires extensive effort and incremental costs to comply, which may affect ARC's profitability. As public policy changes are commonplace, and existing laws and regulations are frequently amended, ARC is unable to predict the future cost or impact of compliance. However, ARC does not expect that any of these laws and regulations will affect its operations materially differently than they would affect other companies with similar operations, size, and financial position. The following are significant areas of government control and regulation affecting ARC's crude oil and natural gas activities. Environment and Health and Safety Matters ARC strives to conduct its operations in a socially and environmentally responsible manner and is required to comply with all federal, provincial, and municipal laws and regulations concerning health and safety, the discharge or other release of materials, and protection of the environment and natural resources. These legal requirements primarily relate to: the discharge or other release of pollutants; assessing the environmental impact of seismic acquisition, drilling and construction activities; the generation, storage, transportation, and disposal of waste materials, including hazardous substances and wastes; the emission of certain gases into the atmosphere; the monitoring, abandonment, reclamation, and remediation of wells and other sites, including sites of former operations; the development of emergency response and spill contingency plans; the protection of threatened and endangered species; and worker protection. Failure by ARC to comply with these laws, regulations, and regulatory initiatives or controls may result in the assessment of sanctions, including administrative, civil and criminal penalties; the imposition of investigatory, remedial and corrective action obligations or the obligation to incur expenditures; the occurrence of restrictions, delays or cancellations in the permitting, development, or expansion of projects; and issuance of injunctions restricting or prohibiting some or all of ARC's activities in a particular area. Historically, ARC's compliance costs have not had a material adverse effect on its financial results. However, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on ARC's business and financial results. ARC owns, leases, or operates numerous assets, some of which have been used for crude oil and natural gas exploration and production activities for several years. ARC also has acquired and disposed of certain assets from third parties whose actions with respect to the management and disposal or release of hydrocarbons, hazardous substances, or wastes at or from such assets were not under ARC's control prior to acquiring them. Under certain environmental laws and regulations, ARC could incur strict joint and several liability from damages to the environment or for remediating hydrocarbons, hazardous substances, or wastes disposed of or released by prior owners or operators. Moreover, an accidental release of materials into the environment during ARC's operations could cause the Company to incur significant costs and liabilities. Over time, the trend in laws and regulations impacting crude oil and natural gas production operations has been to place more restrictions and limitations on these activities. If existing legal requirements change or new legislative, regulatory, or executive initiatives are developed and implemented in the future, ARC may be required to make significant, unanticipated expenditures. Exploration and Development Activities ARC's crude oil and natural gas operations are subject to laws and regulations that relate to matters including: the acquisition of seismic data; location, drilling, and casing of wells; hydraulic fracturing; well production operations; disposal of produced water; regulation of transportation and sale of crude oil, condensate, NGLs, and natural gas; surface land usage; calculation and disbursement of royalty payments; and restoration of lands disturbed for crude oil and natural gas operations. Development and production operations are subject to various regulations, including regulations requiring permits for the drilling and completion of wells, the posting of security in connection with development and production activities and the filing of reports related to production operations. Alberta and British Columbia, and certain municipalities in which ARC operates also regulate one or more of the following: the location of wells; the method of drilling and casing wells; the method and ability to fracture stimulate wells; the surface use and restoration of lands upon which wells are drilled and infrastructure and equipment are located; the disposal of produced water; the plugging and abandoning of wells; and notices to surface land owners and other third parties. ARC's crude oil and natural gas wells are completed and stimulated through the use of hydraulic fracturing technology. Hydraulic fracturing involves the injection of water, sand, and small amounts of additives under high pressure into tight rock formations to stimulate the production of crude oil and natural gas. While the majority of the sand remains underground to hold open the fractures, a significant amount of the water and chemical additives flow back and are then either reused or safely disposed of at sites that are approved and permitted by provincial regulatory authorities. Hydraulic fracturing is regulated at the provincial level through permitting and other compliance requirements. Regulatory scrutiny of hydraulic fracturing has generally focused on issues related to water storage, management and handling, increased seismicity in the areas in which hydraulic fracturing takes place, and local stakeholder engagement. Regulatory authorities actively monitor and investigate hydraulic fracturing activities in their jurisdictions and have imposed, or have considered imposing, various conditions and restrictions on drilling and completions activities involving hydraulic fracturing. Such restrictions, conditions, or prohibitions could lead to operational delays and increased operating and compliance costs, and could delay or prevent the development of crude oil, condensate, NGLs, and natural gas from formations which would not be economically viable without the use of hydraulic fracturing. Project Approvals Approvals and licenses from relevant government and regulatory bodies are required to carry out or make modifications to ARC's crude oil and natural gas exploration and production activities. The project approval process can involve environmental assessment, stakeholder and Indigenous consultation, and inputs regarding project concerns and public hearings and may include various conditions and commitments arising throughout the consultation and review process. In 2019, the Canadian Energy Regulator Act (Canada) and Impact Assessment Act (Canada) ("IAA") came into force. The IAA was later amended in 2024 following a Supreme Court of Canada decision that found certain aspects of the IAA were unconstitutional largely on the basis that it represented significant federal overreach into provincial affairs. In November 2024, Alberta referred to the Alberta Court of Appeal to determine whether the amended IAA is unconstitutional in light of the Supreme Court of Canada decision. These laws and their amendments, and the legal and political responses of provincial governments to these laws, impact the way large energy-related projects are approved and have created uncertainty concerning the governmental approval processes, timelines and designation criteria associated with large infrastructure projects. Though ARC does not typically own, operate, permit, or construct projects which would appear to fall under the scope of the IAA, aspects of ARC's crude oil and gas natural operations may rely on these projects being owned, operated, permitted, and constructed by others. Indigenous Involvement in Resources Development Indigenous communities are significant stakeholders in the development of resources in Western Canada. Those interests range from equity ownership and participation in major energy infrastructure projects to broader stakeholder involvement whose interests must be considered and accommodated in order for resource development to proceed, including the issuance of regulatory permits and approvals. The Canadian federal and provincial governments have a duty to consult with Indigenous Peoples when contemplating actions that may adversely affect the asserted or proven Indigenous or treaty rights and, in certain circumstances, accommodate their concerns. The scope of the duty to consult by federal and provincial governments varies with the circumstances and is often the subject of ongoing litigation. In 2021, the federal government introduced legislation to implement the United Nations Declaration on the Rights of Indigenous Peoples ("UNDRIP"). In British Columbia, the provincial government must take measures necessary to ensure the laws of British Columbia are consistent with the principles of UNDRIP. The fulfillment of the duty to consult Indigenous Peoples and any associated accommodations may affect ARC's ability to obtain or renew permits, leases, licences and other approvals, or to meet the terms and conditions of those approvals and impact the timing for executing development plans. ARC recognizes the value of collaboration with Indigenous communities. ARC strives to communicate and build relationships with the Indigenous communities where it operates so that resource development on Indigenous lands and territories can advance in a manner that is respectful and beneficial to all those involved. Climate Change and Greenhouse Gas Emissions Greenhouse gases, which include among other items, methane, carbon dioxide, nitrous oxide and various fluorinated gases ("GHGs") are typically emitted throughout all phases of the crude oil and natural gas supply chain and in end user consumption through activities such as power generation and motorized transportation. The Government of Canada and the provincial governments of Alberta and British Columbia have been increasingly focused on GHG emissions and climate change issues in recent years, resulting in new laws and regulations designed to limit existing emissions of GHGs, and to restrict or eliminate future GHG emissions. Some of these laws and regulations are in effect, while others remain in various phases of review, discussion, or implementation. In 2023, the Government of Canada announced plans to implement a national emissions cap-and-trade model and in 2024 the Oil and Gas Emissions Cap Regulations were proposed. The proposed regulations would phase in a cap-and-trade system between 2026 and 2030 and have it apply to operators of upstream crude oil and natural gas facilities and LNG facilities that undertake certain industrial activities specified under the proposed regulations. Industrial activities would include, among other things, production of LNG, processing of natural gas or natural gas condensates and bitumen and other crude oil production. Many of the federal government initiatives have, by legislative design, caused the provincial governments of Alberta and British Columbia to evaluate, and in some cases, enact their own laws and regulations in response to federal government initiatives focused on GHG emissions, particularly in the areas of output-based pricing systems and the regulation of methane emissions from crude oil and natural gas operations. Output-Based Pricing Systems In 2019, the Greenhouse Gas Pollution Pricing Act (the "GGPPA") came into force in Canada. This federal regime implemented an output-based pricing system which imposes a price (cost) on CO 2e for large industry and a fuel charge system. In March 2025, the Government of Canada amended the GGPPA to eliminate the fuel charge system. To ensure there is a uniform price on emissions across Canada, the GGPPA regime applies in provinces and territories that request it, and those jurisdictions that do not have their own equivalent emissions pricing systems in place meeting the federal standards, commonly referred to as the "federal backstop program". In 2019, the federal government approved Alberta's TIER Regulation which applies to facilities that emitted 100,000 tonnes or more of CO 2e per year in 2016, or any subsequent year, or those that import more than 10,000 tonnes of hydrogen annually. The TIER Regulation satisfies the federal benchmark stringency requirements for emissions sources covered in the TIER Regulation, however, the federal backstop program continues to apply to emissions sources not covered by the regulation. The provincial carbon pricing system in British Columbia satisfies all requirements of the GGPPA and applies in the place of the federal regime in all respects. In December 2025, Alberta amended the TIER Regulation to, among other things, include direct investment of on-site emissions reduction technologies as an option for compliance. The carbon tax payable in Alberta will continue to increase at a rate of $15 per tonne per year, until reaching $170 per tonne in 2030. In May 2025, the Government of Alberta froze the carbon tax at $95 per tonne. Methane Regulations In 2020, the Government of Canada's Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) (the "Federal Methane Regulations") came into force to reduce emissions of methane from the crude oil and natural gas sector by using new control measures intended to reduce unintentional leaks and the intentional venting of methane, and ensuring that crude oil and natural gas operations use low-emission equipment and processes. Among other things, the Federal Methane Regulations limit how much methane upstream crude oil and natural gas facilities are permitted to vent. The regulations aim to reduce the crude oil and natural gas sector's methane emissions by 40 per cent to 45 per cent by 2025, relative to 2012 emissions. Proposed amendments to the Federal Methane Regulations are expected to come into force in 2027. These amendments introduce, among other items, new prohibitions and limits on certain intentional emissions, a new risk-based approach around unintentional emissions, and a new performance-based approach for compliance that relies on continuous emissions monitoring systems. The governments of Alberta and British Columbia have each enacted provincial regulations designed to lower annual methane emissions from the crude oil and natural gas sector. In 2025, the governments of Canada and British Columbia entered into an equivalency agreement for the Federal Methane Regulations not applying in British Columbia until 2030. The equivalency agreement between the governments of Canada and Alberta expired in October 2025, and a new equivalency agreement is being negotiated with the intent that the federal regulations will not apply in Alberta. Environmental Protection Other than its asset retirement obligation ("ARO"), ARC does not separately track the financial effects of environmental protection requirements on its capital expenditures and net income, all of which are included in ARC's other capital expenditures and operating expense . With respect to ARO, the provinces of Alberta and British Columbia have each implemented similar liability management programs for upstream crude oil and natural gas wells, facilities, and pipelines. These programs are designed to assess a licensee's ability to address its suspension, abandonment, remediation, and reclamation liabilities. ARC maintains a planned and scheduled approach to its ARO. For further information on ARC's ARO refer to the section entitled " Asset Retirement Obligation " contained within the MD&A, available on ARC's website at www.arcresources.com and on SEDAR+ at www.sedarplus.ca . Corporate Policies ARC is committed to the prudent development of our assets in accordance with sound corporate governance and workplace policies. We believe that maintaining high standards of business conduct is essential to the long-term success of the Company. Our Code of Business Conduct and Ethics (the "Code") reinforces our expectation that all directors, officers, employees, and other representatives will conduct themselves with a high standard of professionalism and ethical behaviour. The Code specifically outlines the standards required for business integrity, accuracy of records and reporting, conflicts of interest, insider trading, protection and proper use of ARC's assets, reporting of illegal or unethical behaviour, and other matters. The Code is applicable to all directors, officers, employees, and contractors. On an annual basis, all directors, officers, employees, and contractors are required to read and acknowledge their understanding of the Code in writing. In addition, ARC has a Code of Ethics for Senior Financial Officers and a quarterly certification process to ensure their compliance with ethical business conduct, financial reporting requirements and filings, and accurate reporting of operational results. This Code of Ethics for Senior Financial Officers is signed by the Chief Executive Officer and Chief Financial Officer to indicate their compliance and is reviewed by the Policy and Board Governance Committee each quarter. Copies of the Code and the Code of Ethics for Senior Financial Officers can be found on ARC's website at www.arcresources.com and on SEDAR+ at www.sedarplus.ca . ARC has a Respectful Workplace Policy that supplements the Code. ARC requires high standards of professional and ethical conduct from all persons representing ARC. Our values of respect, integrity, trust, and community are core to every decision we make. The policy outlines ARC's commitment to fostering a work environment that is respectful, inclusive, and free of all forms of discrimination, bullying, harassment, sexual harassment, and workplace violence. All new employees are required to review and acknowledge the policy in writing. We conduct regular and ongoing education and training for all employees related to fostering a respectful workplace. ARC has a Human Rights Policy documenting its protection of human rights and ensuring a respectful workplace environment, free from discrimination or harassment. ARC prioritizes safe working conditions in accordance with applicable laws and industry best practices. The policy outlines the human rights due diligence ARC includes in its own operations and in the communities in which it operates. ARC has a Health and Safety Policy which details ARC's expectations on workplace health and safety matters and affirms ARC's belief that the health, safety, and well-being of our employees, contractors, and the communities in which we operate is a main priority. ARC has a strong safety culture that is embedded in our core values and is fundamental in delivering our organizational purpose. ARC follows a people-centric approach and values strong safety leadership starting from the top down. ARC has three focus areas with respect to delivering strong safety performance: (i) implementing strong systems to effectively manage risk and prevent harm on our worksites; (ii) providing adequate training and empowering our people by setting out clear safety expectations; and (iii) fostering a culture of empowered safety leadership. Employees are provided with comprehensive training which is supported by ongoing communication, systems, and processes. Risk Factors A discussion of ARC's risk factors is contained in the section entitled " Risk Factors" in the MD&A, which section is incorporated by reference herein. Also see other documents filed by ARC from time to time available on SEDAR+ at www.sedarplus.ca . STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION The statement of reserves data and other oil and gas information is set forth below (the "Statement"). The effective date of the Statement is December 31, 2025. The Statement conforms to the requirements of NI 51-101. The reserves data set forth below is based upon an evaluation by GLJ and contained in the GLJ Report dated February 3, 2026. The reserves data summarizes our reserves and the net present values of future net revenues for these reserves, using forecast prices and costs prior to provision for interest, general and administrative expenses, and the impact of any financial risk management activities. Reserves evaluation includes abandonment and reclamation costs for all assets with attributed reserves as well as future drilling locations attributed proved and/or probable reserves. Future net revenues have been presented on a before-tax and after-tax basis. We engaged GLJ to provide an evaluation of proved and proved plus probable reserves. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the forecast prices and cost assumptions will be attained, and variances could be material. The recovery and reserves estimates provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein. Readers should review the definitions and information contained in " Definitions and Notes to Reserves Data Tables " in conjunction with the following tables and notes. For more information as to the risks involved, see the section entitled " Risk Factors " contained within the MD&A, available on ARC's website at www.arcresources.com and on SEDAR + at www.sedarplus.ca . The Report on Reserves Data by GLJ on Form 51-101F2 and the Report of Management and Directors on Reserves Data and Other Information on Form 51-101F3 are attached as Appendices A and B to this Annual Information Form. Disclosure of Reserves Data Summary of 2025 Crude Oil and Natural Gas Reserves - Based on Forecast Prices and Costs Company Gross Reserves Tight Oil (Mbbl) (1) NGLs (Mbbl) (2)(3) Total Oil and NGLs (Mbbl) Shale Gas (MMcf) (4) Total Oil Equivalent (Mboe) PROVED Developed Producing 10,900 238,203 249,103 2,805,413 716,672 Developed Non-producing 2,472 6,921 9,393 61,561 19,653 Undeveloped 6,642 214,687 221,329 2,917,783 707,626 TOTAL PROVED 20,014 459,811 479,825 5,784,757 1,443,951 PROBABLE 12,597 292,420 305,017 3,170,991 833,515 TOTAL PROVED PLUS PROBABLE 32,611 752,231 784,842 8,955,748 2,277,467 Company Net Reserves Tight Oil (Mbbl) (1) NGLs (Mbbl) (2)(3) Total Oil and NGLs (Mbbl) Shale Gas (MMcf) (4) Total Oil Equivalent (Mboe) PROVED Developed Producing 8,639 193,791 202,431 2,537,511 625,349 Developed Non-producing 2,070 5,728 7,798 56,713 17,250 Undeveloped 5,475 176,998 182,473 2,631,511 621,059 TOTAL PROVED 16,184 376,518 392,702 5,225,736 1,263,658 PROBABLE 9,682 225,460 235,142 2,791,830 700,447 TOTAL PROVED PLUS PROBABLE 25,866 601,978 627,844 8,017,566 1,964,105 Includes non-material amounts of Light Crude Oil, Medium Crude Oil, and Heavy Crude Oil. Includes associated NGLs for both Conventional and Shale/Tight Reservoirs and includes condensate, propane, and butane. Condensate and Pentanes Plus represent 64 per cent of proved producing NGLs, 67 per cent of total proved NGLs, and 68 per cent of total proved plus probable NGLs. Includes a non-material amount of Conventional Natural Gas. Net Present Value of Future Net Revenues - Based on Forecast Prices and Costs Before-tax Net Present Value (1) ($ millions) Undiscounted Discounted at 5% Discounted at 10% Discounted at 15% Discounted at 20% PROVED Developed Producing 13,265 11,683 10,007 8,707 7,724 Developed Non-producing 422 351 299 261 232 Undeveloped 10,398 6,576 4,242 2,804 1,875 TOTAL PROVED 24,085 18,610 14,548 11,772 9,831 PROBABLE 19,334 11,482 7,540 5,372 4,060 TOTAL PROVED PLUS PROBABLE 43,418 30,091 22,088 17,144 13,892 After-tax Net Present Value (1)(2)(3) ($ millions) Undiscounted Discounted at 5% Discounted at 10% Discounted at 15% Discounted at 20% PROVED Developed Producing 11,061 9,963 8,600 7,515 6,687 Developed Non-producing 322 267 228 198 176 Undeveloped 7,916 4,886 3,008 1,853 1,114 TOTAL PROVED 19,299 15,117 11,835 9,567 7,977 PROBABLE 14,851 8,773 5,705 4,026 3,018 TOTAL PROVED PLUS PROBABLE 34,150 23,890 17,540 13,593 10,994 Reflects values inclusive of estimated abandonment and reclamation for all active assets with attributed reserves. Based on ARC's estimated tax pools at year-end 2025. The after-tax net present value of the future net revenue attributed to ARC's crude oil and natural gas assets reflects the tax burden on the assets on a standalone basis and does not necessarily reflect the business entity tax-level situation or tax planning. ARC's financial statements and the MD&A, available on ARC's website at www.arcresources.com and on SEDAR+ at www.sedarplus.ca , should be consulted for information at the business entity level. Total Future Net Revenues (Undiscounted) - Based on Forecast Prices and Costs Future Net Revenue Future Net Reserves Category Operating Development Abandonment and Reclamation before Income Income Revenue after Income ($ millions) Revenue Royalties Expense Costs Costs (1) Taxes Taxes Taxes Proved Reserves 56,804 9,023 14,414 7,943 1,339 24,085 4,785 19,299 Proved plus Probable Reserves 95,037 17,011 21,839 11,283 1,486 43,418 9,268 34,150 Reflects estimated abandonment and reclamation for all active assets with attributed reserves. Future Net Revenues by Production Group - Based on Forecast Prices and Costs Reserves Category Production Group Future Net Revenue before Income Taxes (Discounted at 10% per Year) ($ millions) Per boe Proved Reserves Tight Oil (1)(2) 738 14.77 Shale Gas (3)(4) 13,810 11.38 Total 14,548 11.51 Proved Plus Probable Reserves Tight Oil (1)(2) 1,053 13.67 Shale Gas (3)(4) 21,035 11.15 Total 22,088 11.25 Including solution gas and other by-products. Includes non-material amounts of Light Crude Oil, Medium Crude Oil, and Heavy Crude Oil. Including by-products, condensate, and pentanes plus but excluding solution gas and other by-products from crude oil wells. Includes a non-material amount of Conventional Natural Gas. Forecast Prices and Costs Forecast prices and costs are prices and costs that are generally acceptable, in the opinion of GLJ, as being a reasonable outlook of the future as of the evaluation effective date. To the extent that there are fixed or presently determinable future prices or costs to which we are legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs have been incorporated into the forecasts. The forecast cost and price assumptions include increases in wellhead selling prices and take into account inflation with respect to future operating and capital costs. Crude oil, natural gas, and NGLs benchmark prices reference a Three Consultant Average January 1, 2026 price forecast and exchange rates which reflect current forward commodity prices as at December 31, 2025, in accordance with the COGE Handbook, which states that major benchmark commodity price forecasts, up to and including the second full forecast year, should not deviate from current forward commodity prices by more than 20 per cent. Three Consultant Average January 1, 2026 Price Forecast and Inflation Rate Assumptions Natural Crude Oil Gas Edmonton Liquids Prices NYMEX Henry WTI Edmonton Hardisty Cromer Hub (1) AECO Exchange Cushing Par Price Heavy Medium Gas Price Gas Price Pentanes Inflation Rate (3) Oklahoma 40° API 12° API 29.3° API (US$/ (Cdn$/ Propane Butane Plus Rate (2) (US$/ Forecast (US$/bbl) (Cdn$/bbl) (Cdn$/bbl) (Cdn$/bbl) MMBtu) MMBtu) (Cdn$/bbl) (Cdn$/bbl) (Cdn$/bbl) (%/Year) Cdn$) 2026 59.92 77.54 60.09 75.60 3.74 3.00 25.10 36.95 80.01 - 0.728 2027 65.10 83.60 64.94 81.51 3.78 3.30 27.28 39.79 86.19 2.0 0.737 2028 70.28 90.18 71.16 87.92 3.85 3.49 29.67 42.87 92.83 2.0 0.740 2029 71.93 92.32 72.84 90.01 3.93 3.58 30.37 43.89 95.05 2.0 0.740 2030 73.37 94.17 74.30 91.82 4.01 3.65 30.98 44.77 96.94 2.0 0.740 2031 74.84 96.06 75.80 93.65 4.09 3.72 31.60 45.67 98.89 2.0 0.740 2032 76.34 97.98 77.32 95.53 4.17 3.80 32.23 46.58 100.87 2.0 0.740 2033 77.87 99.93 78.87 97.44 4.26 3.88 32.87 47.51 102.88 2.0 0.740 2034 79.42 101.93 80.46 99.38 4.34 3.95 33.53 48.46 104.94 2.0 0.740 2035 81.01 103.97 82.07 101.37 4.43 4.03 34.20 49.43 107.04 2.0 0.740 Thereafter (4) (4) (4) (4) (4) (4) (4) (4) (4) 2.0 0.740 GLJ assigns a value to ARC's existing natural gas physical sales contracts at Dawn, Chicago, Ventura, and Malin consuming markets based upon GLJ's forecasted differential to NYMEX Henry Hub, contracted volumes, and transportation costs. No incremental value is assigned to potential future contracts which were not in place as of December 31, 2025. Inflation rates for forecasting costs. Exchange rates used to generate the benchmark reference prices in this table. Prices escalate two per cent per year from 2036. ARC's weighted average realized prices for the year ended December 31, 2025, were $3.51 per Mcf for shale gas; $81.75 per barrel for tight oil; $86.21 per barrel for condensate; and $21.81 per barrel for NGLs. Definitions and Notes to Reserves Data Tables In the tables set forth above and elsewhere in this Annual Information Form, the following definitions and other notes are applicable: " Gross " means: in relation to our interest in production and reserves, our interest (operating and non-operating) before deduction of royalties and without including any royalty interest to us; in relation to wells, the total number of wells in which we have an interest; and in relation to properties, the total area of properties in which we have an interest. " Net " means: in relation to our interest in production and reserves, our interest (operating and non-operating) after deduction of royalty obligations, plus our royalty interest in production or reserves; in relation to wells, the total number of wells in which we have an interest multiplied by the working interest we owned; and in relation to our interest in a property, the total area in which we have an interest multiplied by the working interest we owned. Columns may not add due to rounding. The forecast price and cost assumptions assumed the continuance of current laws and regulations. All factual data supplied to GLJ was accepted as represented. No field inspection was conducted. The crude oil, natural gas, and NGLs reserves estimates presented in the GLJ Report are based on the definitions and guidelines contained in the CSA Notice 51-324 - Revised Glossary to NI 51-101 Standards of Disclosure for Oil and Gas Activities and the COGE Handbook. A summary of those definitions are set forth below. Reserves Categories Reserves are estimated remaining quantities of crude oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on analysis of drilling, geological, and geophysical data; through the use of established technology; and within specified economic conditions. Reserves are classified according to the degree of certainty associated with the estimates. Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Other criteria that must also be met for the categorization of reserves are provided in the COGE Handbook. Each of the reserves categories (proved and probable) may be divided into developed and undeveloped categories: Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing. Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty. Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown. Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved and probable) to which they are assigned. In multi-well pools it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities, and completion intervals in the pool and their respective development and production status. Levels of Certainty for Reported Reserves The qualitative certainty levels referred to in the definitions above are applicable to individual reserves entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions: at least a 90 per cent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and at least a 50 per cent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves. A qualitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods. Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in the COGE Handbook. Reconciliations of Changes in Reserves The following table sets forth the reconciliation of our gross reserves as at December 31, 2025, using forecast price and cost estimates derived from the GLJ Report. Gross reserves as at December 31, 2025 and as at December 31, 2024 include working interest reserves before royalties payable and without including gross royalties receivable. Key highlights include: The Kakwa Acquisition resulted in increases to reserves in all categories. Production increased through the Attachie Phase I facility, increasing proved producing reserves. Continued strong well performance across ARC's Montney assets drove positive proved producing, total proved, and proved plus probable technical revisions in the Shale Gas and NGLs categories. The exception was in the proved plus probable category for NGLs where there was a negative technical revision due to underperformance of wells drilled in the Attachie area. Development across ARC's Montney assets resulted in positive extensions and improved recovery reserve additions in all categories. Minor negative revisions in the economic factors category are due to changes in forecast commodity prices. Reconciliation of Gross Reserves by Principal Product Type Tight Oil (Mbbl) (1) NGLs (Mbbl) (2)(3) Total Oil and NGLs (Mbbl) Shale Gas (MMcf) (4) Total Oil Equivalent (Mboe) PROVED PRODUCING December 31, 2024 10,790 192,383 203,172 2,513,596 622,105 Extensions and Improved Recovery (5) 3,034 58,051 61,084 446,386 135,482 Technical Revisions 843 29,247 30,090 282,008 77,091 Acquisitions 467 28,137 28,605 172,653 57,380 Dispositions - - - - - Economic Factors (748) (17,037) (17,785) (125,841) (38,758) Production (6) (3,485) (52,578) (56,063) (483,389) (136,628) December 31, 2025 10,900 238,203 249,103 2,805,413 716,672 PROVED December 31, 2024 19,695 420,856 440,551 5,303,400 1,324,451 Extensions and Improved Recovery (5) 1,200 36,864 38,064 535,726 127,352 Technical Revisions 2,905 23,918 26,824 288,416 74,893 Acquisitions 471 52,916 53,388 277,452 99,630 Dispositions - - - - - Economic Factors (773) (22,165) (22,937) (136,849) (45,746) Production (6) (3,485) (52,578) (56,063) (483,389) (136,628) December 31, 2025 20,014 459,811 479,825 5,784,757 1,443,951 PROBABLE December 31, 2024 12,604 251,195 263,799 3,059,631 773,738 Extensions and Improved Recovery (5) 557 30,705 31,261 85,368 45,489 Technical Revisions (782) (28,928) (29,710) (188,944) (61,200) Acquisitions 106 30,562 30,668 125,045 51,509 Dispositions - - - - - Economic Factors 113 8,885 8,998 89,891 23,980 December 31, 2025 12,597 292,420 305,017 3,170,991 833,515 PROVED PLUS PROBABLE December 31, 2024 32,299 672,051 704,350 8,363,031 2,098,188 Extensions and Improved Recovery (5) 1,757 67,569 69,325 621,094 172,841 Technical Revisions 2,123 (5,009) (2,886) 99,472 13,693 Acquisitions 577 83,479 84,056 402,498 151,139 Dispositions - - - - - Economic Factors (660) (13,280) (13,940) (46,958) (21,766) Production (6) (3,485) (52,578) (56,063) (483,389) (136,628) December 31, 2025 32,611 752,231 784,842 8,955,748 2,277,467 Includes non-material amounts of Light Crude Oil, Medium Crude Oil, and Heavy Crude Oil. Includes associated NGLs for both Conventional and Shale/Tight Reservoirs. Condensate and Pentanes Plus represent 72 per cent of total proved NGLs, 73 per cent of probable NGLs, and 72 per cent of proved plus probable NGLs in the December 31, 2024 opening balance. Condensate and Pentanes Plus represent 67 per cent of total proved NGLs, 69 per cent of probable NGLs, and 68 per cent of proved plus probable NGLs in the December 31, 2025 closing balance. Includes a non-material amount of Conventional Natural Gas. Reserve additions for Discoveries, Infill Drilling, Extensions, and Improved Recovery are combined and reported as "Extensions and Improved Recovery". Production does not include royalty interest volumes and therefore differs from the production reported in the Production History table within this document. Future Development Costs The following table sets forth development costs deducted in the estimation of our future net revenue attributed to the reserves categories noted below: Future Development Costs Year Proved Reserves ($ millions) Proved Plus Probable Reserves ($ millions) 2026 1,629 1,693 2027 1,550 1,701 2028 1,111 1,673 2029 707 1,361 2030 765 1,223 Remainder 2,181 3,632 Total: Undiscounted 7,943 11,283 Total: Discounted at 10% per year 5,980 8,124 ARC expects to fund the development costs of its reserves through a combination of funds from operations and other sources of capital. Changes in forecasted future development capital occur annually as a result of development activities, acquisition and disposition activities, and capital cost estimates that reflect the independent qualified reserves evaluator's best estimate of what it will cost to bring the proved plus probable undeveloped reserves on production at that time. Undiscounted future development costs ("FDC") for proved plus probable undeveloped reserves increased $1.0 billion compared to year-end 2024, to total $11.3 billion at year-end 2025. The increase in FDC was primarily driven by the Kakwa Acquisition, as well as the booking of proved plus probable undeveloped reserves as a result of additional undeveloped locations. Estimates of reserves and future net revenues have been made assuming the development of each property, in respect of which the estimate is made, will occur, without regard to the likely availability to us of funding required for the development. There can be no guarantee that funds will be available or that we will allocate funding to develop all of the reserves attributed in the GLJ Report. Failure to develop those reserves would have a negative impact on future earnings. The interest or other costs of external funding are not included in the reserves and future net revenue estimates and would reduce reserves and future net revenues to some degree depending upon the funding sources utilized. We do not anticipate that interest or other funding costs would make development of any property uneconomic. Undeveloped Reserves Undeveloped reserves are attributed by GLJ in accordance with standards and procedures contained in the COGE Handbook. Proved undeveloped reserves are those reserves that can be estimated with a high degree of certainty and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. Probable undeveloped reserves are those reserves that are less certain to be recovered than proved reserves and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. The following tables disclose, by each product type, the volumes of proved and probable undeveloped reserves that were first attributed by GLJ in each of the most recent three financial years. Proved Undeveloped Reserves (1) Tight Oil (Mbbl) Shale Gas (Bcf) NGLs (Mbbl) Total (Mboe) First Attributed Total at Year-end First Attributed Total at Year-end First Attributed Total at Year-end First Attributed Total at Year-end 2023 1,298 6,835 607.2 2,745.0 58,976 218,891 161,482 683,233 2024 2,408 7,222 373.1 2,594.7 29,185 215,289 93,784 654,967 2025 518 6,642 607.7 2,917.8 54,343 214,687 156,143 707,626 Probable Undeveloped Reserves (1) Tight Oil (Mbbl) Shale Gas (Bcf) NGLs (Mbbl) Total (Mboe) First Attributed Total at Year-end First Attributed Total at Year-end First Attributed Total at Year-end First Attributed Total at Year-end 2023 893 8,793 604.1 1,948.3 65,328 178,812 166,898 512,328 2024 615 9,385 432.2 2,226.6 40,542 183,574 113,189 564,059 2025 1,630 9,475 604.7 2,315.2 80,853 222,190 183,262 617,539 There are no undeveloped reserves attributed to Light Crude Oil, Medium Crude Oil, Heavy Crude Oil, or Conventional Natural Gas in the last three years. As of December 31, 2025, undeveloped reserves represented 49 per cent of total proved reserves and 58 per cent of proved plus probable reserves. Over 44 per cent of the proved plus probable undeveloped reserves are located in the Kakwa area, with the rest located in our Montney assets in northeast British Columbia and other areas in northern Alberta. We have planned a program to develop a portion of the undeveloped reserves in 2026 and 2027, focusing on continued Montney development. Reserves were assigned adhering to the practices outlined within the COGE Handbook, with uncertainty applied at the individual location level to account for the potential variability in well results. There were 771 (771 net) total proved, undeveloped locations assigned to be developed in ARC's core properties over the next ten years in the 2025 evaluation which account for 708 MMboe of reserves volumes. 73 per cent of the total proved FDC is forecasted to be spent in the next five years. In addition to these total proved undeveloped locations are 351 (351 net) future development locations assigned probable reserves only, with a timeline to develop these reserves over the next ten years. 68 per cent of the total proved plus probable FDC is forecasted to be spent in the next five years. These probable locations and additional probable reserves assigned to proved locations account for 618 MMboe. The total proved plus probable undeveloped volumes account for 1,325 MMboe and are all scheduled to produce within the capacity of existing facilities or facilities to which capital has been assigned within the reserves evaluation. Drilling programs for these assets have been underway for several years and are anticipated to continue for some time due to the large inventory of high-quality locations that qualify for assignment of reserves. Ongoing activity in these assets will continue to supply ARC infrastructure as well as long-term natural gas supply contracts secured by ARC. Consistent with ARC's principles to maintain a strong balance sheet and demonstrate capital discipline, capital forecasts in the GLJ Report do not exceed levels historically invested by ARC in any given year. The pace of development of the proved and probable undeveloped reserves is influenced by many factors, including the outcomes of the annual drilling and reservoir evaluations, the price for crude oil and natural gas, and a variety of economic factors and conditions. There are a number of factors that could result in delayed or cancelled development, including the following: (i) changing economic conditions (due to pricing, operating, and capital expenditure fluctuations, or changing regulation and/or fiscal or environmental policy); (ii) changing technical conditions (including production anomalies, such as accelerated depletion); (iii) a larger development program may need to be spread out over several years to optimize capital allocation and facility utilization; and (iv) surface access issues (including those relating to landowners, weather conditions, and regulatory approvals). For more information as to the risks involved, refer to the section entitled " Risk Factors " contained within the MD&A, available on ARC's website at www.arcresources.com and on SEDAR+ at www.sedarplus.ca . Significant Factors or Uncertainties Affecting Reserves Data We have a significant amount of proved undeveloped and probable undeveloped reserves assigned to the Montney. Sophisticated technology and large capital expenditures are required to bring these undeveloped reserves into production. Degradation in future commodity price forecasts relative to the forecast in the GLJ Report may have a negative impact on the economics and timing of the development of undeveloped reserves, unless significant reduction in the future costs of development are realized. The failure to obtain all necessary licenses, permits, and other approvals to carry out exploration, development, and operating activities on ARC's assets would negatively impact the economics and timing of developing ARC's undeveloped reserves. See the sections entitled " Risk Factors - Indigenous Land and Rights Claims" and " Risk Factors - Regulatory Approvals" within the MD&A, available on ARC's website at www.arcresources.com and on SEDAR+ at www.sedarplus.ca . The following table sets forth information respecting anticipated future abandonment and reclamation costs for surface leases, wells, facilities, and pipelines, including those where reserves are attributed. These abandonment and reclamation costs have been calculated outside of the reserves process and exclude any costs for undeveloped reserves. As at December 31, 2025, ARC had 3,482 net wells for which we expect to incur abandonment and reclamation costs. Abandonment and Reclamation Costs Escalated at an average of 2.0% Undiscounted ($ millions) Discounted at 10% (1) ($ millions) Total as at December 31, 2025 792.9 171.6 Anticipated to be paid in 2026 20.0 18.5 Anticipated to be paid in 2027 17.0 14.6 Anticipated to be paid in 2028 17.0 13.6 Costs used to determine ARC's asset retirement obligation in the financial statements have been discounted using a liability-specific risk-free rate of 3.9 per cent. For more information with respect to our reclamation and abandonment obligations for properties with no attributed reserves, see the section entitled " Statement of Reserves Data and Other Oil and Gas Information - Properties with no Attributed Reserves " contained within this Annual Information Form. In addition, see the section entitled " Further Information Respecting Abandonment Obligations " below. Further Information Respecting Abandonment Obligations Abandonment and reclamation costs are incurred to restore shut-in and producing wells, facilities, and pipelines used in ARC's operations to the standard imposed by the applicable regulatory authorities. We include abandonment and reclamation costs for our property, plant and equipment ("PP&E") and exploration and evaluation assets ("E&E") in our annual budgeting process for the budget year and a provision for these costs is recognized at the present value of Management's best estimate of total expenditures required to settle the liability as at the date of the balance sheet. These ongoing environmental obligations are expected to be provided for with funds from operations. A portion of the liability is settled each year and facilities are scheduled to be decommissioned once all of the wells associated with a particular facility have been suspended or abandoned. Our model for estimating the amount and timing of future abandonment and reclamation expenditures was created at an operating area level. Estimated expenditures for each operating area are based on numerous sources, including information provided by provincial regulatory authorities, industry peer groups, area-specific data from a third-party liability management firm, and proprietary data from our operations. All wells, pipelines, facilities, and associated costs are then assigned to a specific geographic region which is consistent with the methodology used by the Alberta Energy Regulator and the British Columbia Energy Regulator. No estimate of salvage value is netted against the estimated cost. The estimates are reviewed periodically, and any changes are applied prospectively. The provision for site restoration and abandonment is based on current legal and constructive requirements, technology, price levels, and expected plans for remediation. Actual costs and cash outflows can differ from estimates because of changes in laws and regulations, public expectations, market conditions, discovery and analysis of site conditions, and changes in technology. For more information, see Note 5 " Management Judgments and Estimation Uncertainty " in the financial statements, available on ARC's website at www.arcresources.com and on SEDAR+ at www.sedarplus.ca . In estimating the future net revenues disclosed in this Annual Information Form, the GLJ Report, in the proved plus probable category, deducted $1.5 billion (undiscounted) and $67.9 million (discounted at 10 per cent) for abandonment and reclamation costs for all active assets with attributed reserves. Refer to Note 15 " Asset Retirement Obligation" in the financial statements and to the section entitled " Asset Retirement Obligation" contained within the MD&A, available on ARC's website at www.arcresources.com and on SEDAR+ at www.sedarplus.ca . Core Operating Areas The following is a description of ARC's principal crude oil and natural gas assets as at December 31, 2025. Information in respect of gross and net acres and well counts are as at December 31, 2025. The working interest in gross/net acres and wells as at December 31, 2025 may not directly correspond to the stated production for the year, which would only include production after, or up to, the effective date of any acquisition or disposition. ARC's crude oil and natural gas assets described below are all located in the Western Canadian Sedimentary Basin and onshore within the Canadian provinces of Alberta and British Columbia. Except as set forth under the heading " Statement of Reserves Data and Other Oil and Gas Information - Undeveloped Reserves ", there are no material districts to which reserves have been attributed that are capable of producing but which are not producing at December 31, 2025, and there are no material statutory or mandatory relinquishments, surrenders, back-ins, or changes in ownership provisions. When determining gross and net acreage for two or more lease agreements covering the same lands but different rights, the acreage is reported for each lease agreement. Alberta ARC's assets in northern Alberta are located in the Montney formation. ARC is one of the largest operators in the region with an average working interest of 93 per cent in approximately 953,117 gross acres (885,206 net acres), which includes land holdings of 1,032 net Montney sections. ARC drilled 94 gross operated wells in 2025 with an average working interest of 100 per cent, excluding any service wells. ARC has access to approximately 1,205 MMcf/d of natural gas and 170,000 bbl/d of liquids-handling capacity through facilities in the region, including its owned-and-operated infrastructure. British Columbia ARC's assets in northeast British Columbia are located in the Montney formation. ARC is one of the largest operators in the region with an average working interest of 95 per cent in approximately 619,690 gross acres (588,397 net acres), which includes land holdings of 682 net Montney sections. ARC drilled 47 gross operated wells in 2025 with an average working interest of 100 per cent, excluding any service wells. ARC has access to approximately 965 MMcf/d of natural gas and 53,000 bbl/d of liquids-handling capacity through facilities in the region, including its owned-and-operated infrastructure. Crude Oil and Natural Gas Wells The following table sets forth the number and status of wells in which ARC had a working interest as at December 31, 2025. Province Crude Oil Wells (1) Na tural Gas Wells (2) Producing Gross Net Non-Producing Gross Net Producing Gross Net Non-Producing Gross Net Alberta 320 299 189 166 1,238 1,179 281 199 British Columbia 113 113 13 12 707 706 111 106 Total (3) 433 412 202 178 1,945 1,885 392 305 Includes Light Crude Oil wells, Medium Crude Oil wells, Heavy Crude Oil wells, and Tight Oil wells. Includes Conventional Natural Gas wells and Shale Gas wells. Excludes abandoned, water source, water injection, and disposal wells. Properties with No Attributed Reserves The following table sets out by province our properties with no attributed reserves as at December 31, 2025. Undeveloped Acres Gross Net Alberta 533,232 492,745 British Columbia 397,612 366,117 Total 930,844 858,862 Undeveloped properties are lands that have not been assigned reserves; however, in certain of our undeveloped lands, reserves may have been assigned in other formations. Undeveloped acres are mineral agreement specific. The table above includes vertically stacked agreements within the same areal footprint. ARC has no material work commitments related to our undeveloped acres in 2026. There are no material expiries in our core holdings in 2026. Significant Factors or Uncertainties for Properties with No Attributed Reserves ARC's business model focuses on our core operations, with little to no capital allocated to the acquisition, exploration, or development of properties with no attributed reserves. Therefore, there are not expected to be any significant factors or uncertainties that would affect such properties at this time and the abandonment and reclamation costs associated with these properties are not expected to be material. For information with respect to our reclamation and abandonment obligations for our properties to which reserves have been attributed, see the section entitled " Statement of Reserves Data and Other Oil and Gas Information -Further Information Respecting Abandonment Obligations" in this Annual Information Form. Forward Contracts and Transportation Commitments ARC is exposed to market risks resulting from fluctuations in commodity prices, foreign exchange rates, and interest rates, in the normal course of operations. ARC maintains a risk management program including the use of derivative instruments to reduce the volatility of revenues, increase the certainty of funds from operations, and to protect acquisition and development economics. The Company may also potentially be exposed to losses in the event of default by the counterparties to our derivative instruments. The risk is managed by diversifying our derivative portfolio amongst a number of investment-grade counterparties, including counterparties within our lending syndicate and by conducting regular credit reviews on all counterparties. A summary of our financial contracts in respect of hedging activities can be found in Note 17 " Financial Instruments and Market Risk Management " in the financial statements and in the section entitled " Risk Management Contracts " contained within the MD&A, available on ARC's website at www.arcresources.com and on SEDAR+ at www.sedarplus.ca . A part of our ongoing strategy is to secure transportation capacity to ensure our production moves to market over the short and long term. ARC believes that securing firm takeaway capacity is part of prudent management of our business, and has secured sufficient capacity for existing production and anticipated future growth. Our transportation commitments available for future physical deliveries of crude oil, natural gas, and NGLs exceed ARC's expected related future production of our proved reserves, based on the GLJ Report. The amount and estimated cost of excess firm takeaway capacity as compared to our proved reserves forecast is presented in the table below: Excess Capacity Above Proved Reserves (1) Zero to Five Years Beyond Five Years Natural Gas (MMcf/d) 631 229 Crude Oil and NGLs (Mbbl/d) 9 18 Estimated Cost ($ millions) 571 1,038 1) Amounts are undiscounted and reflect the total in excess of all proved reserves. Total proved reserves comprise 63 per cent of total proved plus probable reserve...

View stock analysis, news, and events for Arc Resources Ltd.