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ARC Resources Ltd. Earnings Release 2025
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Earnings Release
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ARC RESOURCES LTD. REPORTS YEAR-END 2025 RESULTS AND RESERVES
NEWS RELEASE
Calgary, February 5, 2026 (ARX - TSX) ARC Resources Ltd. ("ARC" or the "Company") today reported its fourth quarter and year-end 2025 financial and operational results as well as its year-end 2025 reserves.
CORPORATE HIGHLIGHTS
Fourth Quarter Results
- Fourth quarter production averaged a record 408,382 boe(1) per day (58 per cent natural gas and 42 per cent crude oil and liquids(2)), which included 118,898 barrels per day of crude oil and condensate production, the highest in ARC's 30-year history. Production per share(3) increased 10 per cent compared to the fourth quarter of 2024.
- ARC generated funds from operations of \$874 million(4) (\$1.52 per share(4)) and cash flow from operating activities of \$668 million (\$1.16 per share(4)).
- ARC realized an average natural gas price of \$3.77 per Mcf(4), which is \$1.43 greater than the average AECO 7A Monthly Index price.
- Free funds flow was \$415 million(4) (\$0.72 per share(4)), and net income was \$260 million or \$0.45 per share. ARC distributed \$257 million (\$0.45 per share) to shareholders through the base dividend and share repurchases, and allocated the remainder to debt reduction.
- ARC declared dividends of \$120 million (\$0.21 per share(4)) and repurchased 5.1 million common shares for \$137 million under its normal course issuer bid ("NCIB").
- ARC invested \$459 million in capital expenditures(4) during the fourth quarter, which contributed to total capital expenditures of \$1.9 billion in 2025, which was within Company guidance.
- Subsequent to December 31, 2025, ARC executed an agreement to purchase assets in the Kakwa area of Alberta for approximately \$160 million. The transaction is expected to close in February 2026.
- Net debt(4) decreased by \$191 million compared to the third quarter of 2025. As at December 31, 2025, net debt was \$2.9 billion or 0.9 times funds from operations(4) .
Year-end 2025 Highlights
- • ARC generated record annual average production of 374,336 boe per day (59 per cent natural gas and 41 per cent crude oil and liquids), an increase of 10 per cent per share compared to 2024.
- ARC recognized funds from operations of \$3.2 billion (\$5.48 per share), and generated free funds flow of \$1.3 billion (\$2.20 per share) in 2025.
- ARC distributed 75 per cent of free funds flow to shareholders through its base dividend and share repurchases. The remainder was allocated to debt reduction, allowing ARC to further strengthen its balance sheet.
- • ARC increased its base dividend for the fifth consecutive year. ARC's Board of Directors (the "Board") approved an 11 per cent increase to the quarterly dividend, from \$0.19 to \$0.21 per share (\$0.84 per share, per annum).
- • ARC's annual average realized natural gas price of \$3.51 per Mcf was 89 per cent or \$1.65 per
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Mcf greater than the average AECO 7A Monthly Index price. This marks the 13th consecutive year that ARC's market diversification strategy resulted in a realized natural gas price that exceeded AECO by 20 per cent or greater.
- Natural gas curtailments at Sunrise due to low natural gas prices during the third and fourth quarters of 2025 reduced full-year average production by approximately 12,000 boe per day (approximately 70 MMcf per day). The curtailments preserved resource for periods when prices were higher, and allowed ARC to defer approximately \$50 million of capital.
- In July 2025, ARC completed the acquisition of condensate-rich Montney assets in the Kakwa area of Alberta from Strathcona Resources Ltd. in an all-cash transaction valued at approximately \$1.6 billion(5) (the "Kakwa Acquisition").
- ARC executed an agreement for the earning and development of up to 36 new contiguous sections in the Montney with the Tsaa Dunne Za Energy Limited Partnership – a limited partnership owned by Halfway River First Nation.
- 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 liquefied natural gas ("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.
2025 Reserves(1)(6)
- ARC reported record reserves across all categories in 2025. Proved developed producing ("PDP") and total proved plus probable ("2P") reserves increased by 15 per cent and nine per cent, respectively, compared to 2024.
- For the 18th consecutive year, ARC replaced greater than 120 per cent of 2P reserves.
- For the 20th consecutive year, ARC reported positive technical revisions on a total proved ("1P") and 2P basis.
- ARC's before-tax net present value ("NPV") of 2P reserves, discounted at 10 per cent was \$38.71 per share(4) at December 31, 2025. The 2P NPV considers the development of 23 per cent of ARC's internally identified inventory(7), providing a long runway for future development and reserve growth.
- ARC's reserve life index ("RLI") increased across all three categories. ARC's RLI increased to 4.8 years on a PDP basis, 9.6 years on a 1P, and 15.1 years on a 2P basis.
ARC's consolidated financial statements and notes thereto (the "financial statements") and Management's Discussion and Analysis ("MD&A") as at and for the three months and year ended December 31, 2025, are available on ARC's website at www.arcresources.com and under ARC's SEDAR+ profile at www.sedarplus.ca. The disclosure under the section entitled "Non-GAAP and Other Financial Measures" in ARC's MD&A as at and for the three months and year ended December 31, 2025 (the "2025 Annual MD&A") is incorporated by reference into this news release.
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- (1) ARC has adopted the standard six thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") of crude oil ratio when converting natural gas to barrels of oil equivalent ("boe"). Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf:1 bbl 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.
- (2) Throughout this news release, crude oil ("crude oil") refers to light, medium, and heavy crude oil product types as defined by National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). Condensate is a natural gas liquid as defined by NI 51-101. Throughout this news release, natural gas liquids ("NGLs") comprise all natural gas liquids as defined by NI 51-101 other than condensate, which is disclosed separately. Throughout this news release, crude oil and liquids ("crude oil and liquids") refers to crude oil, condensate, and NGLs.
- (3) Represents average daily production divided by the diluted weighted average common shares outstanding for the three months ended December 31.
- (4) This is a specified financial measure. See "Non-GAAP and Other Financial Measures" of this news release and in the 2025 Annual MD&A for additional disclosure, which is incorporated by reference.
- (5) The purchase price was approximately \$1.6 billion for the assets acquired in the Kakwa Acquisition before purchase price adjustments and unrelated equipment and land.
- (6) GLJ Ltd. ("GLJ") conducted an Independent Qualified Reserves Evaluation ("Reserves Evaluation"), dated February 3, 2026 and effective December 31, 2025, which was prepared in accordance with definitions, standards, and procedures in the Canadian Oil and Gas Evaluation ("COGE") Handbook and NI 51-101. The Reserves Evaluation was based on the GLJ Ltd., Sproule ERCE, McDaniel & Associates Consultants Ltd. Three Consultant Average ("3CA") forecast pricing and foreign exchange rates at January 1, 2026.
- (7) Internally identified inventory refers to drilling locations identified by ARC based on its own internal evaluation and which were not independently verified by GLJ. Such inventory does not constitute reserves or resources as defined under NI 51-101.
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FINANCIAL AND OPERATIONAL RESULTS
| (Cdn\$ millions, except per share amounts(1), boe amounts, | Three Months Ended | Year Ended | |||
|---|---|---|---|---|---|
| and common shares outstanding) | September 30, 2025 |
December 31, 2025 |
December 31, 2024 |
December 31, 2025 |
December 31, 2024 |
| FINANCIAL RESULTS | |||||
| Net income | 214.4 | 259.9 | 370.3 | 1,275.1 | 1,124.1 |
| Per share | 0.37 | 0.45 | 0.63 | 2.19 | 1.88 |
| Cash flow from operating activities | 713.3 | 668.1 | 650.9 | 3,093.5 | 2,348.6 |
| Per share | 1.23 | 1.16 | 1.10 | 5.31 | 3.94 |
| Funds from operations | 779.0 | 874.3 | 770.4 | 3,192.4 | 2,472.5 |
| Per share | 1.34 | 1.52 | 1.30 | 5.48 | 4.15 |
| Free funds flow | 282.6 | 415.4 | 420.4 | 1,283.7 | 627.0 |
| Per share | 0.49 | 0.72 | 0.71 | 2.20 | 1.05 |
| Dividends declared | 109.6 | 120.0 | 112.2 | 451.8 | 416.2 |
| Per share | 0.19 | 0.21 | 0.19 | 0.78 | 0.70 |
| Cash flow used in investing activities | 2,160.0 | 475.5 | 423.3 | 3,536.0 | 1,906.2 |
| Capital expenditures(2) | 496.4 | 458.9 | 350.0 | 1,908.7 | 1,845.5 |
| Long-term debt | 2,784.8 | 2,878.1 | 1,387.4 | 2,878.1 | 1,387.4 |
| Net debt | 3,056.6 | 2,866.1 | 1,335.6 | 2,866.1 | 1,335.6 |
| Common shares outstanding, weighted average diluted (millions) |
581.5 | 574.1 | 592.3 | 582.6 | 596.4 |
| Common shares outstanding, end of period (millions) | 575.7 | 570.6 | 589.6 | 570.6 | 589.6 |
| OPERATIONAL RESULTS | |||||
| Production | |||||
| Crude oil and condensate (bbl/day) | 113,959 | 118,898 | 102,977 | 106,984 | 87,266 |
| Natural gas (MMcf/day) | 1,172 | 1,410 | 1,418 | 1,324 | 1,307 |
| NGLs (bbl/day) | 50,014 | 54,500 | 42,998 | 46,625 | 42,787 |
| Total (boe/day) | 359,236 | 408,382 | 382,341 | 374,336 | 347,908 |
| Average realized price | |||||
| Crude oil (\$/bbl)(3) | 82.75 | 73.63 | 91.46 | 81.75 | 91.46 |
| Condensate (\$/bbl)(3) | 84.66 | 78.45 | 95.52 | 86.21 | 97.00 |
| Natural gas (\$/Mcf)(3) | 2.75 | 3.77 | 2.58 | 3.51 | 2.37 |
| NGLs (\$/bbl)(3) | 17.47 | 18.97 | 26.83 | 21.81 | 24.59 |
| Average realized price (\$/boe)(3) | 38.23 | 38.30 | 38.25 | 39.68 | 36.15 |
| Netback per boe | |||||
| Commodity sales from production (\$/boe)(3) | 38.23 | 38.30 | 38.25 | 39.68 | 36.15 |
| Royalties (\$/boe)(3) | (4.18) | (3.07) | (4.07) | (3.93) | (4.12) |
| Operating expense (\$/boe)(3) | (6.36) | (5.18) | (4.18) | (5.39) | (4.68) |
| Transportation expense (\$/boe)(3) | (4.46) | (4.83) | (5.03) | (5.04) | (5.21) |
| Netback per boe (\$/boe)(3) | 23.23 | 25.22 | 24.97 | 25.32 | 22.14 |
| TRADING STATISTICS(4) | |||||
| High price | 29.27 | 27.20 | 27.40 | 31.56 | 27.40 |
| Low price | 23.67 | 23.54 | 22.48 | 22.63 | 19.44 |
| Close price | 25.38 | 25.75 | 26.07 | 25.75 | 26.07 |
| Average daily volume (thousands of shares) | 5,046 | 5,431 | 3,747 | 4,431 | 3,610 |
(1) Per share amounts, with the exception of dividends, are based on weighted average diluted common shares.
(2) Refer to the section entitled "About ARC Resources Ltd." contained within the 2025 Annual MD&A for historical capital expenditures, which information is incorporated by reference into this news release.
(3) This is a specified financial measure. See "Non-GAAP and Other Financial Measures" of this news release and in the 2025 Annual MD&A for additional disclosure, which information is incorporated by reference.
(4) Trading prices are stated in Canadian dollars on a per share basis and are based on intra-day trading on the Toronto Stock Exchange.
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OUTLOOK
ARC remains committed to delivering on its strategy to deliver sustainable free funds flow per share growth to provide shareholders with a durable and attractive return. Consistent with previous years, the strategy is underpinned by its longstanding principles of safety, capital discipline, and preserving a strong balance sheet.
Operations Update
Attachie
At over 360 net sections, Attachie is a large condensate-rich asset and remains in the early stages of development. In 2025, its first year of operations, ARC focused on capturing and applying learnings to deliver repeatable well performance and improved capital efficiencies to ensure long-term profitability at the asset.
The early production results from the most recent Upper Montney pads at Attachie, brought on stream in late 2025 and early 2026, have been variable and below expectations. In response, ARC has adjusted its development schedule to further evaluate well performance and determine an appropriate development plan for Attachie going forward. As a result, ARC is removing asset-level production guidance at Attachie for 2026.
ARC remains confident in the long-term potential of the resource at Attachie. The Company will continue to advance the asset in a disciplined manner, allocating capital to further refine well design and apply operational learnings.
2026 Guidance
Corporate guidance for 2026 remains unchanged. Asset-level production contribution and capital allocation may shift throughout the year as the development plan for Attachie evolves.
- Average annual production of between 405,000 and 420,000 boe per day (61 per cent natural gas and 39 per cent crude oil and liquids).
- Planned capital expenditures of between \$1.8 to \$1.9 billion(1).
- Based on the current forward curve and Company guidance, ARC estimates 2026 free funds flow of approximately \$1.2 billion(2), essentially all of which is earmarked for shareholder returns via the base dividend and share repurchases.
ARC's 2026 corporate guidance is based on various commodity price scenarios and economic conditions. Production guidance does not include any assumption for possible natural gas production curtailments due to low natural gas prices. Certain guidance estimates may fluctuate with commodity price changes and regulatory changes. ARC's guidance provides readers with the information relevant to Management's expectations for financial and operational results for 2026.
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ARC's 2025 and 2026 annual guidance and a review of 2025 actual results are outlined below:
| 2025 Guidance | 2025 Actual | % Variance from 2025 Guidance |
2026 Guidance | |
|---|---|---|---|---|
| Production | ||||
| Crude oil and condensate (bbl/day) | 107,000 - 112,000 | 106,984 | — 105,000 - 115,000 | |
| Natural gas (MMcf/day) | 1,290 - 1,310 | 1,324 | 1 | 1,500 - 1,520 |
| NGLs (bbl/day) | 43,000 - 45,000 | 46,625 | 4 | 48,000 - 52,000 |
| Total (boe/day) | 365,000 - 375,000 | 374,336 | — | 405,000 - 420,000 |
| Expenses (\$/boe)(3) | ||||
| Operating | 5.00 - 5.50 | 5.39 | — | 5.40 - 5.90 |
| Transportation | 5.00 - 5.50 | 5.04 | — | 5.25 - 5.75 |
| General and administrative ("G&A") expense before share-based compensation expense |
1.00 - 1.10 | 1.10 | — | 1.00 - 1.10 |
| G&A - share-based compensation expense | 0.30 - 0.40 | 0.18 | (40) | 0.25 - 0.35 |
| Interest and financing(4) | 0.90 - 1.00 | 0.98 | — | 1.10 - 1.20 |
| Current income tax expense as a per cent of funds from operations(3) |
5 - 10 | 8 | — | 5 - 10 |
| Capital expenditures (\$ billions) | 1.85 - 1.95 | 1.91 | — | 1.8 - 1.9 |
(1) Refer to the section entitled "About ARC Resources Ltd." contained within the 2025 Annual MD&A for historical capital expenditures, which information is incorporated by reference into this news release.
(2) Based on forward pricing as of January 22, 2026 of US\$59 per barrel WTI; C\$2.70 per Mcf AECO.
(3) This is a specified financial measure. See "Non-GAAP and Other Financial Measures" of this news release and in the 2025 Annual MD&A for additional disclosure, which information is incorporated by reference.
(4) Excludes accretion expense.
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FINANCIAL AND OPERATIONAL RESULTS
Production
Fourth Quarter 2025
- • ARC generated record average production during the fourth quarter of 408,382 boe per day (58 per cent natural gas and 42 per cent crude oil and liquids). Production increased seven per cent compared to the fourth quarter of 2024 and 10 per cent on a per share basis.
- The increase year-over-year was driven primarily by the Kakwa Acquisition. During the fourth quarter, production at Kakwa averaged 215,073 boe per day (42 per cent natural gas and 58 per cent crude oil and liquids), which included 124,505 barrels per day of condensate and natural gas liquids.
- Attachie production averaged 28,286 boe per day during the fourth quarter (41 per cent natural gas and 59 per cent crude oil and liquids), and included 13,182 barrels per day of condensate.
- Natural gas production at Sunrise was restored in the fourth quarter when AECO natural gas prices recovered.
Full-Year 2025
- Full-year production averaged 374,336 boe per day (59 per cent natural gas and 41 per cent crude oil and liquids), which was in line with Company guidance.
- This included record average crude oil and condensate production of 106,984 barrels per day, driven primarily by Attachie and the Kakwa Acquisition that closed on July 2, 2025.
- The natural gas production curtailments at Sunrise that occurred from July through October reduced full-year average production by approximately 12,000 boe per day. This allowed ARC to defer approximately \$50 million of capital expenditures earmarked to sustain production at Sunrise.
Funds from Operations, Cash Flow from Operating Activities, and Free Funds Flow
Fourth Quarter 2025
- ARC generated \$874 million (\$1.52 per share) of funds from operations in the fourth quarter. This represents a 13 per cent increase (\$104 million or \$0.22 per share) compared to the same quarter of the prior year, driven primarily by higher production at Kakwa and Attachie.
- ARC reported free funds flow of \$415 million (\$0.72 per share) in the fourth quarter.
Full-Year 2025
- In 2025, ARC generated funds from operations of \$3.2 billion (\$5.48 per share) and cash from operating activities of \$3.1 billion (\$5.31 per share).
- Free funds flow totalled \$1.3 billion (\$2.20 per share) for the year.
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The following table details the change in funds from operations for the fourth quarter of 2025 relative to the third quarter of 2025.
| Funds from Operations Reconciliation | \$ millions | \$/share(1) |
|---|---|---|
| Funds from operations for the three months ended September 30, 2025 | 779.0 | 1.34 |
| Production volumes | ||
| Crude oil and liquids | 45.6 | 0.08 |
| Natural gas | 60.1 | 0.10 |
| Commodity prices | ||
| Crude oil and liquids | (62.5) | (0.11) |
| Natural gas | 132.1 | 0.23 |
| Sales of third-party purchases | 66.2 | 0.11 |
| Interest and other income | 1.4 | — |
| Realized gain on risk management contracts | (11.1) | (0.02) |
| Royalties | 22.7 | 0.04 |
| Expenses | ||
| Operating | 15.6 | 0.03 |
| Transportation | (34.2) | (0.06) |
| Third-party purchases | (65.3) | (0.11) |
| G&A | (23.0) | (0.04) |
| Interest and financing | (1.4) | — |
| Realized loss on foreign exchange | (3.8) | (0.01) |
| Current income tax | (47.0) | (0.08) |
| Other | (0.1) | — |
| Weighted average shares, diluted | — | 0.02 |
| Funds from operations for the three months ended December 31, 2025 | 874.3 | 1.52 |
(1) Per share amounts are based on weighted average diluted common shares.
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The following table details the change in funds from operations for the fourth quarter of 2025 relative to the fourth quarter of 2024.
| Funds from Operations Reconciliation | \$ millions | \$/share(1) |
|---|---|---|
| Funds from operations for the three months ended December 31, 2024 | 770.4 | 1.30 |
| Production volumes | ||
| Crude oil and liquids | 167.9 | 0.28 |
| Natural gas | (2.2) | — |
| Commodity prices | ||
| Crude oil and liquids | (226.7) | (0.39) |
| Natural gas | 154.3 | 0.26 |
| Sales of third-party purchases | 100.4 | 0.17 |
| Interest and other income | (1.5) | — |
| Realized gain on risk management contracts | 21.8 | 0.04 |
| Royalties | 27.8 | 0.05 |
| Expenses | ||
| Operating | (47.9) | (0.08) |
| Transportation | (4.6) | (0.01) |
| Third-party purchases | (96.0) | (0.16) |
| G&A | 18.5 | 0.03 |
| Interest and financing | (10.5) | (0.02) |
| Realized loss on foreign exchange | (5.8) | (0.01) |
| Current income tax | 6.4 | 0.01 |
| Other | 2.0 | — |
| Weighted average shares, diluted | — | 0.05 |
| Funds from operations for the three months ended December 31, 2025 | 874.3 | 1.52 |
(1) Per share amounts are based on weighted average diluted common shares.
Shareholder Returns
- • In 2025, ARC distributed 75 per cent of free funds flow or \$966 million (\$1.66 per share) to shareholders through a combination of dividends and share repurchases under its NCIB. The remainder was allocated to debt reduction to preserve ARC's financial strength.
- In the third quarter of 2025, the Board approved an increase of 11 per cent to the Company's quarterly dividend, from \$0.19 per share to \$0.21 per share (\$0.76 per share to \$0.84 per share, per annum).
- During the fourth quarter, ARC declared dividends of \$120 million (\$0.21 per share) and repurchased 5.1 million common shares under its NCIB at a weighted average price of \$26.86 per share.
- In 2025, ARC repurchased 19.7 million common shares under its NCIB at a weighted average price of \$26.09 per share throughout the year.
- Since commencing its initial NCIB in September 2021, ARC has repurchased approximately 22 per cent (159 million common shares) of its total outstanding shares at a weighted average price of \$17.74 per share.
- ARC intends to distribute essentially all free funds flow to shareholders in 2026 through its growing base dividend and continued share repurchases.
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Operating, Transportation, and General and Administrative Expense
Operating Expense
- ARC's fourth quarter 2025 operating expense of \$5.18 per boe was 19 per cent or \$1.18 per boe lower than the previous quarter. The decrease in operating costs per boe is primarily due to Sunrise volumes being restored and the completion of planned maintenance activity.
- Full-year 2025 operating expense of \$5.39 per boe was in line with Company guidance.
Transportation Expense
- ARC's fourth quarter 2025 transportation expense per boe of \$4.83 decreased by four per cent or \$0.20 per boe compared to the same period in the prior year.
- ARC's full-year 2025 transportation expense of \$5.04 per boe was at the low end of ARC's guidance range of \$5.00 to \$5.50 per boe.
General and Administrative Expense
- • ARC's fourth quarter 2025 general and administrative expense per boe of \$1.26 decreased 33 per cent from the same period of the prior year, primarily due to the revaluation of the liability associated with ARC's share-based compensation plans.
- ARC's full-year 2025 general and administrative expense of \$1.28 per boe decreased 34 per cent compared to the prior year and was slightly lower than the Company guidance range of \$1.30 to \$1.50 per boe.
Cash Flow Used in Investing Activities and Capital Expenditures
- Cash flow used in investing activities was \$476 million during the fourth quarter of 2025. ARC invested \$459 million in capital expenditures to drill 39 wells and complete 32 wells. Drilling activity was focused primarily at Kakwa, Ante Creek, and Attachie.
- Cash flow from investing activities was \$3.5 billion and capital expenditures were \$1.9 billion. ARC drilled 144 wells and completed 157 wells across its asset base in 2025.
The following table details ARC's 2025 drilling and completions activities by area.
| Year ended December 31, 2025 | ||
|---|---|---|
| Area | Wells Drilled | Wells Completed |
| Kakwa | 83 | 80 |
| Attachie | 25 | 33 |
| Greater Dawson | 22 | 25 |
| Ante Creek | 13 | 12 |
| Sunrise | 1 | 7 |
| Total | 144 | 157 |
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Physical Natural Gas Marketing
- • ARC's infrastructure ownership and committed takeaway capacity to U.S. markets played a critical role in capturing higher realized natural gas prices relative to local benchmarks throughout 2025.
- ARC's average realized natural gas price during the fourth quarter of 2025 was \$3.77 per Mcf, which was \$1.43 per Mcf, or 61 per cent, greater than the average AECO 7A Monthly Index price.
- Full-year 2025 market diversification activities resulted in an average realized natural gas price of \$3.51 per Mcf, \$1.65 per Mcf higher than the average AECO 7A Monthly Index price.
Net Debt
- As at December 31, 2025, ARC's long-term debt balance was \$2.9 billion, and its net debt balance was \$2.9 billion, or 0.9 times funds from operations.
- ARC targets its net debt to be less than 1.5 times funds from operations and manages its capital structure to achieve that target over the long-term.
- In conjunction with the Kakwa Acquisition, ARC issued \$1.0 billion aggregate principal amount of senior unsecured notes, obtained a new \$500 million two-year term loan and increased the borrowing capacity under its existing credit facility to \$2.0 billion from \$1.7 billion.
- ARC holds an investment-grade credit rating, which allows the Company to access capital and manage a low-cost capital structure. ARC is committed to maintaining its strong financial position.
Net Income
- ARC recognized net income of \$260 million (\$0.45 per share) during the fourth quarter of 2025, a 30 per cent, or \$110 million decrease compared to the same quarter in the prior year. The decrease in net income compared to the prior year was primarily due to unrealized losses on risk management contracts in the fourth quarter of 2025. This was partially offset by an increase in commodity sales from production, driven by an increase in production volumes.
- In 2025, ARC recognized net income of \$1.3 billion (\$2.19 per share), compared to net income of \$1.1 billion (\$1.88 per share) in 2024. The increase in net income compared to the prior year was primarily due to an increase in production volumes partially offset by an increase in unrealized losses on risk management contracts.
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2025 RESERVES
Highlights
- ARC reported record reserves in 2025 across all categories, including PDP, 1P, and 2P. PDP and 2P reserves increased by 15 per cent and nine per cent, respectively, compared to 2024.
- ARC's before-tax NPV for 2P reserves of \$22.1 billion (discounted at 10 per cent) equates to \$38.71 per share. ARC's 2P NPV includes the development of 23 per cent of ARC's internal estimate of drilling inventory.
- ARC's before-tax PDP NPV of \$17.54 per share, discounted at 10 per cent, increased six per cent year-over-year.
- ARC's NPV was determined using 3CA forecast pricing and foreign exchange rates at January 1, 2026, with a 10-year average WTI price of US\$73.01 per barrel and a 10-year average AECO price of \$3.64 per MMBtu.
- In 2025, ARC replaced 121 per cent of its 2P reserves. For the 18th consecutive year, 2P reserve replacement from development has been 120 per cent of produced reserves or greater.
- 2P reserves of 2,277 MMboe were a Company record, driven by the Kakwa Acquisition and organic reserve growth.
- ARC booked an additional 151 MMboe of 2P reserves as a result of the Kakwa Acquisition.
- PDP finding, development and acquisition ("FD&A") costs, including future development capital ("FDC") of \$15.77 per boe(1) equated to a 1.6 times(1) PDP FD&A recycle ratio.
- FDC for 2P reserves totalled \$11.3 billion at December 31, 2025 compared to \$10.3 billion at December 31, 2024. Total FDC equates to 6.1 times ARC's 2025 capital expenditure guidance, or approximately 3.5 times ARC's estimated 2026 funds from operations based on current forward pricing.
- ARC's RLI is 4.8 years on a PDP basis and 15.1 years on a 2P basis.
(1) This is a specified financial measure. See "Non-GAAP and Other Financial Measures" of this news release and in the 2025 Annual MD&A for additional disclosure, which information is incorporated by reference.
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Reserves Reconciliation
| Reserves Reconciliation Company Gross(1) |
Tight Oil(2) (Mbbl) |
NGLs(3) (Mbbl) |
Total Oil and NGLs(4) (Mbbl) |
Natural Gas(5) (MMcf) |
Oil Equivalent (Mboe) |
|---|---|---|---|---|---|
| Proved Developed Producing | |||||
| Opening Balance, December 31, 2024 | 10,790 | 192,383 | 203,172 | 2,513,596 | 622,105 |
| Extensions and Improved Recovery(6) | 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 | (3,485) | (52,578) | (56,063) | (483,389) | (136,628) |
| Ending Balance, December 31, 2025 | 10,900 | 238,203 | 249,103 | 2,805,413 | 716,672 |
| Total Proved | |||||
| Opening Balance, December 31, 2024 | 19,695 | 420,856 | 440,551 | 5,303,400 | 1,324,451 |
| Extensions and Improved Recovery(6) | 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 | (3,485) | (52,578) | (56,063) | (483,389) | (136,628) |
| Ending Balance, December 31, 2025 | 20,014 | 459,811 | 479,825 | 5,784,757 | 1,443,951 |
| Proved plus Probable | |||||
| Opening Balance, December 31, 2024 | 32,299 | 672,051 | 704,350 | 8,363,031 | 2,098,188 |
| Extensions and Improved Recovery(6) | 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 | (3,485) | (52,578) | (56,063) | (483,389) | (136,628) |
| Ending Balance, December 31, 2025 | 32,611 | 752,231 | 784,842 | 8,955,748 | 2,277,467 |
- (1) Amounts may not add due to rounding.
- (2) Tight Oil includes immaterial amounts of Light, Medium, and Heavy Crude Oil.
- (3) Condensate and pentanes plus represented 69 per cent of PDP NGLs reserves, 72 per cent of total TP NGLs reserves, and 72 per cent of 2P NGLs reserves for the respective opening balances at December 31, 2024. Condensate and pentanes plus represent 64 per cent of PDP NGLs reserves, 67 per cent of TP NGLs reserves, and 68 per cent of 2P NGLs reserves for the respective ending balances at December 31, 2025.
- (4) Total Oil and NGLs represents the summation of Light, Medium, Heavy Oil, and Tight Oil, and NGLs.
- (5) Natural Gas includes shale gas and conventional natural gas product types, as conventional natural gas makes up less than two per cent of total gas and is therefore considered to be immaterial.
- (6) Reserves additions for discoveries, infill drilling, improved recovery, and extensions are combined and reported as "Extensions and Improved Recovery".
{13}------------------------------------------------
Net Present Value Summary
For a summary of the 3CA forecast pricing and foreign exchange rates used to evaluate ARC's reserves, see "2025 Independent Qualified Reserves Evaluation" of this news release.
| (\$ millions) | Undiscounted | Discounted at 10% |
|---|---|---|
| Before-tax NPV(1)(2) | ||
| Proved Developed Producing | 13,265 | 10,007 |
| Proved Developed Non-producing | 422 | 299 |
| Proved Undeveloped | 10,398 | 4,242 |
| Total Proved | 24,085 | 14,548 |
| Probable | 19,334 | 7,540 |
| Proved plus Probable | 43,418 | 22,088 |
| After-tax NPV(1)(2)(3)(4) | ||
| Proved Developed Producing | 11,061 | 8,600 |
| Proved Developed Non-producing | 322 | 228 |
| Proved Undeveloped | 7,916 | 3,008 |
| Total Proved | 19,299 | 11,835 |
| Probable | 14,851 | 5,705 |
| Proved plus Probable | 34,150 | 17,540 |
(1) Amounts may not add due to rounding.
Finding, Development and Acquisition Costs
- • ARC continues to demonstrate the profitability and durability of its Montney assets through low finding and development ("F&D") costs.
- ARC delivered a 2P F&D cost, including FDC, of \$13.49 per boe(1) (\$11.58 per boe excluding FDC), compared to 2024 2P F&D of \$9.19 per boe (\$7.98 per boe excluding FDC).
- Including net acquisitions and dispositions, ARC's 2P FD&A cost, including FDC, was \$14.71 per boe(1) (\$11.50 per boe excluding FDC), compared to 2024 2P FD&A of \$8.90 per boe (\$7.70 per boe excluding FDC).
- • ARC delivered a F&D including FDC recycle ratio of 2.3 times on a PDP basis, and between 1.9 and 2.0 times on a 1P and 2P basis.
(2) Based on NI 51-101 company net interest reserves and 3CA forecast pricing and foreign exchange rates and costs at January 1, 2026.
(3) Based on ARC's estimated tax pools at December 31, 2025.
(4) The after-tax NPV of the future net revenue attributed to ARC's crude oil and natural gas properties reflects the tax burden on the properties on a standalone basis and does not necessarily reflect the business entity tax-level situation or tax planning. For information at the business entity level, see the section entitled Taxes in the 2025 Annual MD&A.
(1) This is a specified financial measure. See "Non-GAAP and Other Financial Measures" of this news release and in the 2025 Annual MD&A for additional disclosure, which information is incorporated by reference.
{14}------------------------------------------------
FD&A costs are provided including and excluding the change in FDC in the table below.
| Including FDC | F&D Cost(1) (\$/boe) |
FD&A Cost(1) (\$/boe) |
F&D Recycle Ratio(1) |
FD&A Recycle Ratio(1) |
|---|---|---|---|---|
| Proved Developed Producing(2) | ||||
| 2025 | 10.95 | 15.77 | 2.3 | 1.6 |
| 2024 | 11.87 | 11.45 | 1.9 | 1.9 |
| 2023 | 10.34 | 9.81 | 2.5 | 2.6 |
| Three-year Average(3) | 11.03 | 12.73 | 2.2 | 1.9 |
| Total Proved(2) | ||||
| 2025 | 12.71 | 15.92 | 2.0 | 1.6 |
| 2024 | 13.42 | 12.99 | 1.6 | 1.7 |
| 2023 | 11.33 | 11.04 | 2.3 | 2.3 |
| Three-year Average(3) | 12.33 | 13.51 | 2.0 | 1.8 |
| Proved plus Probable(2) | ||||
| 2025 | 13.49 | 14.71 | 1.9 | 1.7 |
| 2024 | 9.19 | 8.90 | 2.4 | 2.5 |
| 2023 | 9.17 | 9.03 | 2.8 | 2.9 |
| Three-year Average(3) | 10.19 | 11.13 | 2.4 | 2.2 |
| Excluding FDC | F&D Cost(1) (\$/boe) |
FD&A Cost(1) (\$/boe) |
F&D Recycle Ratio(1) |
FD&A Recycle Ratio(1) |
|---|---|---|---|---|
| Proved Developed Producing(2) | ||||
| 2025 | 10.98 | 15.72 | 2.3 | 1.6 |
| 2024 | 11.69 | 11.27 | 1.9 | 2.0 |
| 2023 | 10.64 | 10.12 | 2.4 | 2.5 |
| Three-year Average(3) | 11.09 | 12.75 | 2.2 | 1.9 |
| Total Proved(2) | ||||
| 2025 | 12.20 | 14.19 | 2.1 | 1.8 |
| 2024 | 12.01 | 11.58 | 1.8 | 1.9 |
| 2023 | 8.19 | 7.97 | 3.1 | 3.2 |
| Three-year Average(3) | 10.45 | 11.39 | 2.3 | 2.1 |
| Proved plus Probable(2) | ||||
| 2025 | 11.58 | 11.50 | 2.2 | 2.2 |
| 2024 | 7.98 | 7.70 | 2.8 | 2.9 |
| 2023 | 5.98 | 5.89 | 4.3 | 4.4 |
| Three-year Average(3) | 7.94 | 8.49 | 3.1 | 2.9 |
(1) F&D and FD&A costs and recycle ratios take into account reserves revisions during the year on a per boe basis, and include FDC.
(2) The aggregate of the exploration and development costs incurred in the financial year and the changes during that year in estimated FDC may not reflect the total F&D and FD&A costs related to reserves additions for that year.
(3) Three-year average F&D and FD&A costs are calculated as the total capital expenditures over the three prior years divided by the total reserves additions over the three prior years. The three-year average recycle ratio is calculated as the three-year F&D or FD&A costs divided by the three-year average netback per boe.
{15}------------------------------------------------
BOARD OF DIRECTORS UPDATE
ARC is pleased to announce the appointment of Jonathan Wright to the Company's Board of Directors, effective immediately. Mr. Wright has more than 35 years of global oil and gas experience with expertise in strategy, operations, engineering, subsurface, marketing and business development. Most recently, Mr. Wright served as President and Chief Executive Officer of NuVista Energy Ltd. where he led the company's transformation to becoming a pure-play Montney producer. Mr. Wright continued to serve on the board of directors of NuVista after his retirement as CEO, until the company was successfully sold to a larger corporation in 2026. He also currently serves on the boards of two private oil and gas companies.
CONFERENCE CALL
ARC's senior leadership team will be hosting a conference call to discuss the Company's fourth quarter and full-year 2025 results on Friday, February 6, 2026, at 8:00 a.m. Mountain Time ("MT").
| Date | Friday, February 6, 2026 |
|---|---|
| Time | 8:00 a.m. MT |
| Dial-in Numbers | |
| Calgary | 403-910-0389 |
| Toronto | 437-900-0527 |
| Toll-free | 1-888-510-2154 |
| Conference ID | 68346 |
| Webcast URL | https://app.webinar.net/qB0xyKMDEKp |
Callers are encouraged to dial in 15 minutes before the start time to register for the event. A replay will be available on ARC's website at www.arcresources.com following the conference call.
{16}------------------------------------------------
CONSOLIDATED BALANCE SHEETS (unaudited)
As at
| Cdn\$ millions | December 31, 2025 | December 31, 2024 |
|---|---|---|
| ASSETS | ||
| Current assets | ||
| Cash and cash equivalents | 7.0 | — |
| Inventory | 17.9 | 12.4 |
| Accounts receivable | 749.2 | 691.0 |
| Prepaid expense | 136.6 | 107.4 |
| Risk management contracts | 135.6 | 190.1 |
| 1,046.3 | 1,000.9 | |
| Risk management contracts | 56.4 | 154.1 |
| Long-term investments | 30.2 | 27.7 |
| Exploration and evaluation assets | 442.4 | 338.1 |
| Property, plant and equipment | 12,514.4 | 10,373.9 |
| Right-of-use and other long-term assets | 972.4 | 956.8 |
| Goodwill | 248.2 | 248.2 |
| Total assets | 15,310.3 | 13,099.7 |
| LIABILITIES | ||
| Current liabilities | ||
| Accounts payable and accrued liabilities | 760.8 | 634.4 |
| Current portion of lease obligations | 112.1 | 92.8 |
| Current portion of long-term debt | 450.0 | — |
| Current portion of other deferred liabilities | 28.6 | 23.3 |
| Current portion of asset retirement obligation | 20.0 | 17.0 |
| Dividends payable | 120.0 | 112.2 |
| Risk management contracts | — | 1.0 |
| 1,491.5 | 880.7 | |
| Risk management contracts | 138.9 | 37.1 |
| Long-term portion of lease obligations | 922.1 | 908.5 |
| Long-term debt | 2,428.1 | 1,387.4 |
| Long-term incentive compensation liability | 28.1 | 76.2 |
| Other deferred liabilities | 113.0 | 95.8 |
| Asset retirement obligation | 473.9 | 414.4 |
| Deferred taxes | 1,450.7 | 1,351.4 |
| Total liabilities | 7,046.3 | 5,151.5 |
| SHAREHOLDERS' EQUITY | ||
| Shareholders' capital | 5,990.6 | 6,194.3 |
| Contributed surplus | 28.4 | 31.6 |
| Retained earnings | 2,247.0 | 1,728.5 |
| Accumulated other comprehensive loss | (2.0) | (6.2) |
| Total shareholders' equity | 8,264.0 | 7,948.2 |
| Total liabilities and shareholders' equity | 15,310.3 | 13,099.7 |
{17}------------------------------------------------
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)
For the three months and years ended December 31
| Three Months Ended | Year Ended | |||
|---|---|---|---|---|
| (Cdn\$ millions, except per share amounts) | 2025 | 2024 | 2025 | 2024 |
| Commodity sales from production | 1,438.8 | 1,345.5 | 5,421.7 | 4,603.7 |
| Royalties | (115.3) | (143.1) | (536.8) | (524.9) |
| Sales of third-party purchases | 322.3 | 221.9 | 1,190.8 | 1,020.2 |
| Total revenue | 1,645.8 | 1,424.3 | 6,075.7 | 5,099.0 |
| Interest and other income | 4.3 | 5.8 | 20.4 | 20.2 |
| Gain (loss) on risk management contracts | (72.5) | 59.2 | 11.0 | 272.7 |
| Total revenue, interest and other income, and gain (loss) on risk management contracts |
1,577.6 | 1,489.3 | 6,107.1 | 5,391.9 |
| Operating | 194.8 | 146.9 | 735.8 | 596.4 |
| Transportation | 181.6 | 177.0 | 689.1 | 662.9 |
| Third-party purchases | 313.5 | 217.5 | 1,164.9 | 1,011.4 |
| General and administrative | 47.4 | 65.9 | 175.6 | 248.1 |
| Interest and financing | 48.3 | 36.2 | 151.3 | 133.8 |
| Impairment (reversal of impairment) of financial assets | (1.5) | 0.6 | (2.8) | 2.3 |
| Depletion, depreciation and amortization and impairment of property, plant and equipment |
447.1 | 372.4 | 1,547.2 | 1,360.7 |
| Loss (gain) on foreign exchange | 2.3 | (6.2) | 16.1 | 1.3 |
| Gain on disposal of assets | — | — | (4.0) | (80.0) |
| Total expenses | 1,233.5 | 1,010.3 | 4,473.2 | 3,936.9 |
| Net income before income taxes | 344.1 | 479.0 | 1,633.9 | 1,455.0 |
| Provision for income taxes | ||||
| Current | 66.0 | 72.4 | 260.0 | 200.4 |
| Deferred | 18.2 | 36.3 | 98.8 | 130.5 |
| Total income taxes | 84.2 | 108.7 | 358.8 | 330.9 |
| Net income | 259.9 | 370.3 | 1,275.1 | 1,124.1 |
| Other comprehensive income | ||||
| Items that may be reclassified to net income in subsequent periods: |
||||
| Net unrealized gain (loss) on foreign currency translation adjustment |
0.2 | (0.5) | 4.2 | 11.7 |
| Comprehensive income | 260.1 | 369.8 | 1,279.3 | 1,135.8 |
| Net income per share Basic |
0.45 | 0.63 | 2.19 | 1.89 |
{18}------------------------------------------------
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY (unaudited)
For the years ended December 31
| (Cdn\$ millions) | Shareholders' Capital |
Contributed Surplus |
Retained Earnings |
Accumulated Other Comprehensive Loss |
Total Shareholders' Equity |
|---|---|---|---|---|---|
| January 1, 2024 | 6,268.2 | 36.1 | 1,141.4 | (17.9) | 7,427.8 |
| Comprehensive income | — | — | 1,124.1 | 11.7 | 1,135.8 |
| Share-based compensation plans | 1.1 | (0.2) | — | — | 0.9 |
| Exercise of share options | 20.8 | (4.3) | — | — | 16.5 |
| Repurchase of shares for cancellation | (93.2) | — | (113.9) | — | (207.1) |
| Change in liability for share purchase commitment |
(2.6) | — | (6.9) | — | (9.5) |
| Dividends declared | — | — | (416.2) | — | (416.2) |
| December 31, 2024 | 6,194.3 | 31.6 | 1,728.5 | (6.2) | 7,948.2 |
| Comprehensive income | — | — | 1,275.1 | 4.2 | 1,279.3 |
| Share-based compensation plans | 2.6 | (1.9) | — | — | 0.7 |
| Exercise of share options | 11.7 | (1.3) | — | — | 10.4 |
| Repurchase of shares for cancellation | (216.8) | — | (306.1) | — | (522.9) |
| Change in liability for share purchase commitment |
(1.2) | — | 1.3 | — | 0.1 |
| Dividends declared | — | — | (451.8) | — | (451.8) |
| December 31, 2025 | 5,990.6 | 28.4 | 2,247.0 | (2.0) | 8,264.0 |
{19}------------------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
For the three months and years ended December 31
| Three Months Ended | Year Ended | |||
|---|---|---|---|---|
| (Cdn\$ millions) | 2025 | 2024 | 2025 | 2024 |
| CASH FLOW FROM OPERATING ACTIVITIES | ||||
| Net income | 259.9 | 370.3 | 1,275.1 | 1,124.1 |
| Add items not involving cash: | ||||
| Unrealized loss (gain) on risk management contracts | 144.0 | (9.5) | 253.0 | (82.4) |
| Depletion, depreciation and amortization and impairment of | ||||
| property, plant and equipment | 447.1 | 372.4 | 1,547.2 | 1,360.7 |
| Unrealized loss (gain) on foreign exchange | — | (2.7) | 3.3 | 5.1 |
| Gain on disposal of assets | — | — | (4.0) | (80.0) |
| Deferred taxes | 18.2 | 36.3 | 98.8 | 130.5 |
| Other | 5.1 | 3.6 | 19.0 | 14.5 |
| Net change in other liabilities | (7.8) | 3.2 | (95.4) | (19.9) |
| Change in non-cash working capital | (198.4) | (122.7) | (3.5) | (104.0) |
| Cash flow from operating activities | 668.1 | 650.9 | 3,093.5 | 2,348.6 |
| CASH FLOW FROM (USED IN) FINANCING ACTIVITIES | ||||
| Draw of long-term debt under revolving credit facilities | 668.5 | 2,188.5 | 6,095.9 | 7,348.0 |
| Issuance of senior notes | — | — | 1,000.0 | — |
| Issuance of term loan | — | — | 500.0 | — |
| Repayment of long-term debt | (575.9) | (2,241.7) | (6,099.9) | (7,111.0) |
| Proceeds from exercise of share options | 0.4 | 1.5 | 10.4 | 16.5 |
| Repurchase of shares | (136.9) | (52.2) | (514.0) | (202.4) |
| Repayment of principal relating to lease obligations | (28.8) | (25.6) | (103.8) | (93.6) |
| Cash dividends paid | (109.6) | (100.8) | (444.0) | (405.7) |
| Change in non-cash working capital | (6.3) | 2.7 | 4.9 | 4.7 |
| Cash flow from (used in) financing activities | (188.6) | (227.6) | 449.5 | (443.5) |
| CASH FLOW USED IN INVESTING ACTIVITIES | ||||
| Business combination | — | — | (1,672.1) | — |
| Acquisition of assets | (2.4) | (8.8) | (17.8) | (13.9) |
| Disposal of assets | — | — | 4.0 | 80.0 |
| Property, plant and equipment development expenditures | (438.8) | (339.0) | (1,819.1) | (1,787.8) |
| Exploration and evaluation asset expenditures | (11.0) | (2.5) | (53.6) | (31.2) |
| Long-term investments | (1.5) | (2.1) | (3.5) | (6.8) |
| Change in non-cash working capital | (21.8) | (70.9) | 26.1 | (146.5) |
| Cash flow used in investing activities | (475.5) | (423.3) | (3,536.0) | (1,906.2) |
| INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS |
4.0 | — | 7.0 | (1.1) |
| CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD | 3.0 | — | — | 1.1 |
| CASH AND CASH EQUIVALENTS, END OF PERIOD | 7.0 | — | 7.0 | — |
| The following are included in cash flow from operating activities: |
||||
| Income taxes paid in cash | 55.1 | 57.4 | 183.3 | 199.7 |
| Interest paid in cash | 44.5 | 24.8 | 129.5 | 117.4 |
{20}------------------------------------------------
NON-GAAP AND OTHER FINANCIAL MEASURES
Throughout this news release and in other materials disclosed by the Company, ARC employs certain measures to analyze its financial performance, financial position, and cash flow. These non-GAAP and other financial measures are not standardized financial measures under IFRS Accounting Standards and may not be comparable to similar financial measures disclosed by other issuers. The non-GAAP and other financial measures should not be considered to be more meaningful than generally accepted accounting principles ("GAAP") measures which are determined in accordance with IFRS Accounting Standards, such as net income, cash flow from operating activities, and cash flow used in investing activities, as indicators of ARC's performance.
Non-GAAP Financial Measures
Capital Expenditures
ARC uses capital expenditures to monitor its capital investments relative to those budgeted by the Company on an annual basis. ARC's capital budget excludes acquisition or disposition activities as well as the accounting impact of any accrual changes and payments under certain lease arrangements. The most directly comparable GAAP measure to capital expenditures is cash flow used in investing activities. The following table details the composition of capital expenditures and its reconciliation to cash flow used in investing activities.
| Three Months Ended | Year Ended | ||||
|---|---|---|---|---|---|
| Capital Expenditures (\$ millions) |
September 30, 2025 |
December 31, 2025 |
December 31, 2024 |
December 31, 2025 |
December 31, 2024 |
| Cash flow used in investing activities | 2,160.0 | 475.5 | 423.3 | 3,536.0 | 1,906.2 |
| Business combination | (1,672.1) | — | — | (1,672.1) | 0 |
| Acquisition of assets | (10.6) | (2.4) | (8.8) | (17.8) | (13.9) |
| Disposal of assets | — | — | — | 4.0 | 80.0 |
| Long-term investments | (0.8) | (1.5) | (2.1) | (3.5) | (6.8) |
| Change in non-cash investing working capital | 9.6 | (21.8) | (70.9) | 26.1 | (146.5) |
| Capitalized right-of-use asset depreciation | 10.3 | 9.1 | 8.5 | 36.0 | 26.5 |
| Capital expenditures | 496.4 | 458.9 | 350.0 | 1,908.7 | 1,845.5 |
Free Funds Flow
ARC uses free funds flow as an indicator of the efficiency and liquidity of ARC's business, measuring its funds after capital investment available to manage debt levels, and return capital to shareholders through dividends and share repurchases. ARC computes free funds flow as funds from operations generated during the period less capital expenditures. Capital expenditures is a non-GAAP financial measure. By removing the impact of current period capital expenditures from funds from operations, Management monitors its free funds flow to inform its capital allocation decisions. The most directly comparable GAAP measure to free funds flow is cash flow from operating activities. The following table details the calculation of free funds flow and its reconciliation to cash flow from operating activities.
{21}------------------------------------------------
| Three Months Ended | Year Ended | ||||
|---|---|---|---|---|---|
| Free Funds Flow (\$ millions) |
September 30, 2025 |
December 31, 2025 |
December 31, 2024 |
December 31, 2025 |
December 31, 2024 |
| Cash flow from operating activities | 713.3 | 668.1 | 650.9 | 3,093.5 | 2,348.6 |
| Net change in other liabilities | 32.5 | 7.8 | (3.2) | 95.4 | 19.9 |
| Change in non-cash operating working capital | 33.2 | 198.4 | 122.7 | 3.5 | 104.0 |
| Funds from operations | 779.0 | 874.3 | 770.4 | 3,192.4 | 2,472.5 |
| Capital expenditures | (496.4) | (458.9) | (350.0) | (1,908.7) | (1,845.5) |
| Free funds flow | 282.6 | 415.4 | 420.4 | 1,283.7 | 627.0 |
Adjusted Net Capital Acquisitions
Adjusted net capital acquisitions is a non-GAAP financial measure used in the determination of FD&A costs, which is a non-GAAP ratio. Adjusted net capital acquisitions is useful as it provides a measure of cash, debt, and share consideration used to acquire crude oil and natural gas assets during the period, net of cash provided by the disposal of any crude oil and natural gas assets during the period. The most directly comparable GAAP measure to adjusted net capital acquisitions is acquisition of crude oil and natural gas assets. The following table details the calculation of adjusted net capital acquisitions and its reconciliation to acquisition of crude oil and natural gas assets.
| Adjusted Net Capital Acquisitions (\$ millions) |
Year Ended December 31, 2025 |
Year Ended December 31, 2024 |
|---|---|---|
| Acquisition of assets | (17.8) | (13.9) |
| Remove: | ||
| Disposal of assets | 4.0 | 80.0 |
| Adjusted net capital acquisitions | (13.8) | 66.1 |
Non-GAAP Ratios
Free Funds Flow per Share
ARC presents free funds flow per share by dividing free funds flow by the Company's diluted or basic weighted average common shares outstanding. Free funds flow is a non-GAAP financial measure. Management believes that free funds flow per share provides investors an indicator of funds generated from the business that could be allocated to each shareholder's equity position.
Finding and Development Costs
ARC calculates F&D costs as capital expenditures divided by the change in reserves within the applicable reserves category. ARC calculates F&D costs, including FDC, as the sum of capital expenditures and the change in FDC required to bring the reserves on production, divided by the change in reserves within the applicable reserves category. Capital expenditures, a non-GAAP financial measure, is used as a component of F&D costs. Management uses F&D costs as a measure of capital efficiency for organic reserves development.
Finding, Development and Acquisition Costs
ARC calculates FD&A costs as the sum of capital expenditures and adjusted net capital acquisitions divided by the change in reserves within the applicable reserves category, inclusive of changes due to acquisitions and dispositions. ARC calculates FD&A costs, including FDC, as the sum of capital expenditures, adjusted net capital acquisitions, and the change in FDC required to bring the reserves on production, divided by the change in reserves within the applicable reserves category, inclusive of changes due to acquisitions and dispositions. Capital expenditures and adjusted net capital acquisitions,
{22}------------------------------------------------
both non-GAAP financial measures, are used as components of FD&A costs. Management uses FD&A costs as a measure of capital efficiency for organic and acquired reserves development.
Recycle Ratio
ARC calculates recycle ratio by dividing the netback per boe by F&D or FD&A costs. Netback per boe is a non-GAAP ratio that uses netback, a non-GAAP financial measure, as a component. Capital expenditures, a non-GAAP financial measure, is used as a component of F&D costs. Capital expenditures and adjusted net capital acquisitions, both non-GAAP financial measures, are used as components of FD&A costs. Management uses recycle ratio to relate the cost of adding reserves to the expected cash flows to be generated.
Supplementary Financial Measures
Before-tax Proved plus Probable Net Present Value per Share
Before-tax 2P NPV per share is comprised of the before-tax NPV for 2P reserves, discounted at 10 per cent, as determined in accordance with NI 51-101, divided by divided by common shares outstanding at the end of the period.
Capital Management Measures
Funds from operations, net debt, and net debt to funds from operations are capital management measures. See Note 16 "Capital Management" in the financial statements and "Non-GAAP and Other Financial Measures" in the 2025 Annual MD&A for information additional disclosures, which information is incorporated by reference into this news release.
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2025 INDEPENDENT QUALIFIED RESERVES EVALUATION
GLJ conducted a Reserves Evaluation, effective December 31, 2025, which was prepared in accordance with definitions, standards, and procedures in the COGE Handbook and NI 51-101. The Reserves Evaluation was based on the 3CA forecast pricing and foreign exchange rates at January 1, 2026, as outlined in the table below. These forecasts reflect current market conditions as defined by current forward commodity prices as at December 31, 2025. This aligns with the COGE Handbook, effective April 1, 2021, 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.
Reserves included herein are stated on a company gross basis (working interest before deduction of royalties without the inclusion of any royalty interest) unless otherwise noted.
ARC's crude oil and natural gas reserves statement for the year ended December 31, 2025, including complete disclosure of the Company's crude oil and natural gas reserves and other crude oil and natural gas information in accordance with NI 51-101, will be disclosed in ARC's Annual Information Form for the year ended December 31, 2025, which will be available on or before March 31, 2026 on ARC's website at www.arcresources.com and under ARC's SEDAR+ profile at www.sedarplus.ca.
Summary of the 3CA January 1, 2026 Forecast Prices and Inflation Rate Assumptions
| 3CA Price | WTI Crude Oil (US\$/bbl) |
Edmonton Light Oil (Cdn\$/bbl) |
NYMEX Henry Hub Natural Gas (US\$/MMBtu) |
AECO Natural Gas (Cdn\$/MMBtu) |
Foreign Exchange (US\$/Cdn\$) |
|||||
|---|---|---|---|---|---|---|---|---|---|---|
| Forecast(1) | 2026 | 2025(2) | 2026 | 2025(2) | 2026 | 2025(2) | 2026 | 2025(2) | 2026 | 2025(2) |
| 2026 | 59.92 | 74.48 | 77.54 | 97.04 | 3.74 | 3.73 | 3.00 | 3.33 | 0.73 | 0.73 |
| 2027 | 65.10 | 75.81 | 83.60 | 97.37 | 3.78 | 3.85 | 3.30 | 3.48 | 0.74 | 0.74 |
| 2028 | 70.28 | 77.66 | 90.18 | 99.80 | 3.85 | 3.93 | 3.49 | 3.69 | 0.74 | 0.74 |
| 2029 | 71.93 | 79.22 | 92.32 | 101.79 | 3.93 | 4.01 | 3.58 | 3.76 | 0.74 | 0.74 |
| 2030 | 73.37 | 80.80 | 94.17 | 103.83 | 4.01 | 4.09 | 3.65 | 3.83 | 0.74 | 0.74 |
| 2031 | 74.84 | 82.42 | 96.06 | 105.91 | 4.09 | 4.17 | 3.72 | 3.91 | 0.74 | 0.74 |
| 2032 | 76.34 | 84.06 | 97.98 | 108.02 | 4.17 | 4.26 | 3.80 | 3.99 | 0.74 | 0.74 |
| 2033 | 77.87 | 85.75 | 99.93 | 110.19 | 4.26 | 4.34 | 3.88 | 4.07 | 0.74 | 0.74 |
| 2034 | 79.42 | 87.46 | 101.93 | 112.39 | 4.34 | 4.43 | 3.95 | 4.15 | 0.74 | 0.74 |
| 2035 | 81.01 | 103.97 | 4.43 | 4.03 | 0.74 | |||||
| Escalate thereafter at(3) |
+2.0% per year |
+2.0% per year |
+2.0% per year |
+2.0% per year |
+2.0% per year |
+2.0% per year |
+2.0% per year |
+2.0% per year |
0.74 | 0.74 |
(1) GLJ assigns a value to ARC's existing physical diversification contracts for natural gas to consuming markets across North America based upon 3CA forecast differential to NYMEX Henry Hub, contracted volumes, and transportation expense. No incremental value was assigned to potential future contracts that were not in place on December 31, 2025.
(2) GLJ assigns a value to ARC's existing physical diversification contracts for natural gas to consuming markets across North America based upon GLJ's forecast differential to NYMEX Henry Hub, contracted volumes, and transportation expense. No incremental value was assigned to potential future contracts that were not in place on December 31, 2024.
(3) Escalated at two per cent per year starting in 2036 in the January 1, 2026 3CA price forecast with the exception of foreign exchange, which remains flat.
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Definitions of Oil and Gas Reserves
Reserves are estimated remaining quantities of crude oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates as follows:
- 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.
Information Regarding Disclosure on Crude Oil and Natural Gas Reserves and Operational Information
In accordance with Canadian practice, production volumes and revenues are reported on a company gross basis, before deduction of Crown and other royalties, and without including any royalty interests, unless otherwise stated. Unless otherwise specified, all reserves volumes in this news release (and all information derived therefrom) are based on company gross reserves using forecast prices and costs.
This news release contains metrics commonly used in the crude oil and natural gas industry. These metrics do not have standardized meanings and may not be comparable to similar metrics disclosed by other issuers. See "Non-GAAP and Other Financial Measures" of this news release and the definitions of reserve replacement, reserves life index and finding and development costs below. Management uses these metrics for its own performance measurements and to provide shareholders with measures to compare ARC's performance over time; however, such measures are not reliable indicators of ARC's future performance and future performance may not compare to the performance in previous periods:
- Reserves replacement is calculated by dividing the annual reserves additions, in boe, by ARC's annual production, in boe. Management uses this measure to determine the relative change of its reserves base over a period of time.
- Reserves life index ("RLI") is calculated by dividing the reserves by the average annual production for that period. Management uses this measure to determine the relative change of its reserves base over a period of time. PDP RLI is calculated by dividing the proved developed producing reserves by the average annual production for that period. 2P RLI is calculated by dividing the proved plus probable reserves by the average annual production for that period. Management uses this measure to determine the relative change of its reserves base over a period of time.
- Finding and development costs are calculated as capital expenditures divided by the change in reserves within the applicable reserves category. See "Non-GAAP and Other Financial Measures" for additional information about this metric.
This news release contains estimates of the NPV of the Company's future net revenue from reserves associated with ARC's assets. Such amounts do not represent the fair market value of such reserves. The recovery and reserve estimates provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. The NPV of the assets' base production is a snapshot in time and is based on the reserves evaluated using applicable pricing assumptions. It should not be assumed that the undiscounted or discounted NPV of future net revenue attributable to the assets represents the fair market value of those assets. The estimates for reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties due to the effects of aggregation. The recovery and reserve estimates of crude oil, natural gas liquids and natural gas reserves are estimates
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only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates relied upon for NPV calculations, herein.
FORWARD-LOOKING INFORMATION AND STATEMENTS
This news release contains certain forward-looking statements and forward-looking information (collectively referred to as "forward-looking information") within the meaning of applicable securities legislation about current expectations regarding the future based on certain assumptions made by ARC. Although ARC believes that the expectations represented by such forward-looking information are reasonable, there can be no assurance that such expectations will prove to be correct. Forward-looking information in this news release is identified by words such as "anticipate", "believe", "ongoing", "may", "expect", "estimate", "plan", "will", "project", "continue", "target", "strategy", "upholding", or similar expressions, and includes suggestions of future outcomes. In particular, but without limiting the foregoing, this news release contains forward-looking information with respect to: ARC's plans to distribute essentially all free funds flow to shareholders in 2026 through a combination of the base dividend and share repurchases; ARC's 2026 capital budget and guidance including, among others, planned capital expenditures, anticipated average annual production in 2026 and the components thereof, operating expenses, transportation expenses, G&A expenses before share-based compensation expense, G&A expenses – share-based compensation expense, interest and financing expenses and current income tax expense as a per cent of funds from operations; estimated 2026 free funds flow and that essentially all of it is earmarked for shareholder returns; the anticipated closing date of the agreement ARC entered into after December 31, 2025 to acquire certain assets in the Kakwa area of Alberta; the anticipated timing of commencement and duration of and volumes under the long-term LNG sale and purchase agreement with EMLAP and commencement of commercial operations at the Cedar LNG Project; ARC's strategy to deliver sustainable free funds flow per share growth to provide shareholders with a durable and attractive return; that ARC's strategy is underpinned by its longstanding principles of safety, capital discipline, and preserving a strong balance sheet; Attachie's stage of development; ARC's plans to evaluate well performance and determine an appropriate development plan for Attachie; ARC's expectations regarding the long-term potential of the resource at Attachie; ARC's goal to continue advancing Attachie in a disciplined manner, allocating capital prudently to further refine well design and apply operational learnings; the possibility that the asset-level production contribution and capital allocation estimates included in ARC's 2026 corporate guidance may shift throughout the year as the development plan for Attachie evolves; net debt targets; the anticipated runway for future reserve growth; and other similar statements. Further, statements relating to reserves and resources are deemed to be forward-looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitably produced in the future. In addition, forwardlooking information may include statements attributable to third-party industry sources. There can be no assurance that the plans, intentions, or expectations upon which these forward-looking statements are based will occur.
Readers are cautioned not to place undue reliance on forward-looking information as ARC's actual results may differ materially from those expressed or implied. ARC undertakes no obligation to update or revise any forward-looking information except as required by law. Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to ARC and others that apply to the industry generally. The material assumptions on which the forward-looking information in this news release are based, and the material risks and uncertainties underlying such forward-looking information, include: the ability to shift capital allocation among ARC's assets; forward pricing assumptions; risks and assumptions related to potential natural gas curtailments due to low natural gas prices; volatility of commodity prices; adverse economic conditions; political uncertainty; lack of capacity in, and/or regulatory constraints and uncertainty regarding, gathering and processing facilities, pipeline systems, and railway lines; indigenous land and rights claims; compliance with environmental regulations; risks relating to climate change, including transition and physical risks; ARC's ability to recruit and retain a skilled workforce and key personnel; development and production risks; project risks; risks relating to failure to obtain regulatory approvals; reputational risks; risks relating to a changing investor sentiment; asset concentration; risks relating to information
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technology systems and cyber security; risks related to hydraulic fracturing (including risks with respect to water production and disposal); liquidity; inflation, cost management and interest rates; third-party credit risks; variations in foreign exchange rates; risks relating to royalty regimes; the impact of competitors; risks related to potential or ongoing litigation; lack of adequate insurance coverage; inaccurate estimation of ARC's reserve volumes; risks related to derivative risk management contracts; limited, unfavorable or a lack of access to capital markets; market access constraints or transportation interruptions, unanticipated operating results or production declines; increased debt levels or debt service requirements; increased costs; potential regulatory and industry changes stemming from the results of court actions affecting regions in which ARC holds assets; 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; the risk that (i) the tariffs that are currently in effect on goods exported from or imported into Canada continue in effect for an extended period of time, the tariffs that have been threatened are implemented, that tariffs that are currently suspended are reactivated, the rate or scope of tariffs are increased, or new tariffs are imposed, including on oil and natural gas, (ii) the U.S. and/or Canada imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas, and (iii) the tariffs imposed or threatened to be imposed by the U.S. on other countries and retaliatory tariffs imposed or threatened to be imposed by other countries on the U.S., will trigger a broader global trade war which could have a material adverse effect on the Canadian, U.S. and global economies, and by extension the Canadian oil and natural gas industry and the Company, including by decreasing demand for (and the price of) oil and natural gas, disrupting supply chains, increasing costs, causing volatility in global financial markets, and limiting access to financing; 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; forecast commodity prices and other pricing assumptions with respect to ARC's 2026 capital expenditure budget; ARC's ability to repurchase its securities under the NCIB; that the previously announced LNG agreements will commence on the timelines anticipated and maintain volumes and pricing as expected; that counterparties to ARC's various agreements will comply with their contractual obligations; expectations and projections made in light of ARC's historical experience; data contained in key modeling statistics; assumptions with respect to global economic conditions and the accuracy of ARC's market outlook expectations for 2026; suspension of or changes to or withdrawals of guidance, and the associated impact to production and capital expenditures; forecast production volumes based on business and market conditions; the accuracy of outlooks and projections contained herein; that future business, regulatory, and industry conditions will be within the parameters expected by ARC, including with respect to prices, margins, demand, supply, product availability, supplier agreements, availability, and cost of labour and interest, exchange, and effective tax rates; projected capital investment levels, the flexibility of capital spending plans, and associated sources of funding; the ability of ARC to complete capital programs and the flexibility of ARC's capital structure; opportunity for ARC to pay dividends and the approval and declaration of such dividends by the Board; the existence of alternative uses for ARC's cash resources which may be superior to payment of dividends or effecting repurchases of outstanding common shares; cash flows, cash balances on hand, and access to ARC's credit facility and other longterm debt being sufficient to fund capital investments; the ability of ARC's existing pipeline commitments and financial risk management transactions to partially mitigate a portion of ARC's risks against wider price differentials; business interruption, property and casualty losses, or unexpected technical difficulties; estimates of quantities of crude oil, natural gas, and liquids from properties and other sources not currently classified as proved; future use and development of technology and associated expected future results; the successful and timely implementation of capital projects or stages thereof; the ability to generate sufficient cash flow to meet current and future obligations; estimated abandonment and reclamation costs, including associated levies and regulations applicable thereto; the retention of key assets; the continuance of existing tax, royalty, and regulatory regimes; estimates with respect to commodity pricing; and other assumptions, risks, and uncertainties described from time to time in the filings made by ARC with securities regulatory authorities, including those risks contained under the heading "Risk Factors" in the 2025 Annual MD&A.
The key assumption underlying ARC's asset-level guidance at Attachie that has been withdrawn in this news release is the anticipated well productivity of Upper Montney pads brought on stream by ARC, primarily in early 2026, and ARC's initial planned pace of development at Attachie in 2026.
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ARC's future shareholder distributions, including but not limited to the payment of dividends, if any, and the level thereof is uncertain. Any decision to pay dividends on ARC's shares (including the actual amount, the declaration date, the record date and the payment date in connection therewith and any special dividends) will be subject to the discretion of the Board and may depend on a variety of factors, including, without limitation, ARC's business performance, financial condition, financial requirements, growth plans, expected capital requirements and other conditions existing at such future time including, without limitation, contractual restrictions and satisfaction of the solvency tests imposed on ARC under applicable corporate law. Further, the actual amount, the declaration date, the record date and the payment date of any dividend are subject to the discretion of the Board. There can be no assurance that ARC will pay dividends in the future.
The forward-looking information in this news release also includes financial outlooks and other related forward-looking information (including production and financial-related metrics) relating to ARC, including, but not limited to: production, capital expenditures, operating expenses, transportation expenses, G&A expenses before share-based compensation expense, G&A expenses – share based compensation expense, interest and financing expenses, current income tax as a per cent of funds from operations and free funds flow. The internal projections, expectations, or beliefs are based on the 2026 capital budget, which is subject to change in light of ongoing results, prevailing economic conditions, commodity prices, and industry conditions and regulations. The financial outlook and other related forward-looking statements are also subject to the same assumptions, risk factors, limitations, and qualifications as set forth above. Any financial outlook and forward-looking information implied by such forward-looking statements are described in the 2025 Annual MD&A, and ARC's most recent annual information form, which are available on ARC's website at www.arcresources.com and under ARC's SEDAR+ profile at www.sedarplus.ca and are incorporated by reference herein.
The forward-looking information contained herein are expressly qualified in their entirety by this cautionary statement. The forward-looking information included in this news release are made as of the date of this news release and, except as required by applicable securities laws, ARC undertakes no obligation to publicly update such forward-looking information to reflect new information, subsequent events or otherwise.
About ARC
ARC Resources Ltd. is a pure-play Montney producer and one of Canada's largest dividend-paying energy companies, featuring low-cost operations. ARC's investment-grade credit profile is supported by commodity and geographic diversity and robust risk management practices around all aspects of the business. ARC's common shares trade on the Toronto Stock Exchange under the symbol ARX.
ARC RESOURCES LTD.
Please visit ARC's website at www.arcresources.com or contact Investor Relations:
E-mail: [email protected] Telephone: (403) 503-8600 Fax: (403) 509-6427 Toll Free: 1-888-272-4900 ARC Resources Ltd. Suite 1500, 308 - 4 Avenue SW Calgary, AB T2P 0H7