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Supplementary Information for Exploration and Production Activities | 12 Months Ended
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Sep. 30, 2025
Supplementary Information for Exploration and Production Activities Unaudited [Abstract] |
Supplementary Information for Exploration and Production Activities | Supplementary Information for Exploration and Production Activities (unaudited, except for Capitalized Costs Relating to Exploration and Production Activities) The Company follows authoritative guidance related to exploration and production activities that aligns the reserve estimation and disclosure requirements with the requirements of the SEC Modernization of Oil and Gas Reporting rule, which the Company also follows. The SEC rules require companies to value their year-end reserves using an unweighted arithmetic average of first day of the month commodity price for each month within the twelve month period prior to the end of the reporting period. The following supplementary information is presented in accordance with the authoritative guidance regarding disclosures about exploration and production activities and related SEC authoritative guidance. Capitalized Costs Relating to Exploration and Production Activities
| At September 30
| 2025 |  | 2024
| (Thousands)
Proved Properties(1) | $ | 7,719,339 |  |  | $ | 7,079,903 |
Unproved Properties | 112,432 |  |  | 200,986 |
| 7,831,771 |  |  | 7,280,889 |
Less — Accumulated Depreciation, Depletion and Amortization | 5,374,360 |  |  | 5,004,299 |
| $ | 2,457,411 |  |  | $ | 2,276,590 |
(1)Includes asset retirement costs of $233.9 million and $175.2 million at September 30, 2025 and 2024, respectively. Costs related to unproved properties are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized. Although the timing of the ultimate evaluation or disposition of the unproved properties cannot be determined, the Company expects the majority of its acquisition costs associated with unproved properties to be transferred into the amortization base by 2030. It expects the majority of its development and exploration costs associated with unproved properties to be transferred into the amortization base by 2027. Following is a summary of costs excluded from amortization at September 30, 2025:
| Total as of September 30, 2025 |  | Year Costs Incurred
|  | 2025 |  | 2024 |  | 2023 |  | Prior
| (Thousands)
Acquisition Costs | $ | 103,508 |  |  | $ | 1,277 |  |  | $ | 8,136 |  |  | $ | 86,038 |  |  | $ | 8,057 |
Development Costs | 8,464 |  |  | 6,267 |  |  | 1,077 |  |  | 922 |  |  | 198 |
Exploration Costs | 460 |  |  | 460 |  |  | — |  |  | — |  |  | — |
Capitalized Interest | — |  |  | — |  |  | — |  |  | — |  |  | — |
| $ | 112,432 |  |  | $ | 8,004 |  |  | $ | 9,213 |  |  | $ | 86,960 |  |  | $ | 8,255 |
Costs Incurred in Property Acquisition, Exploration and Development Activities
| Year Ended September 30
| 2025 |  | 2024 |  | 2023
| (Thousands)
United States |
Property Acquisition Costs: |  |  |  |  |
Proved | $ | 13,680 |  |  | $ | 17,069 |  |  | $ | 33,190 |
Unproved | 18,826 |  |  | 19,526 |  |  | 129,061 |
Exploration Costs(1) | 21,562 |  |  | 53,519 |  |  | 10,055 |
Development Costs(2) | 443,311 |  |  | 429,151 |  |  | 553,469 |
Asset Retirement Costs | 58,680 |  |  | 46,017 |  |  | 8,363 |
| $ | 556,059 |  |  | $ | 565,282 |  |  | $ | 734,138 |
(1)Amounts for 2025, 2024 and 2023 include capitalized interest of zero, $0.1 million and zero respectively. (2)Amounts for 2025, 2024 and 2023 include capitalized interest of zero, $0.7 million and $0.1 million, respectively. For the years ended September 30, 2025, 2024 and 2023, the Company spent $246.3 million, $305.6 million and $342.0 million, respectively, developing proved undeveloped reserves. Results of Operations for Producing Activities
| Year Ended September 30
| 2025 |  | 2024 |  | 2023
United States | (Thousands, except per Mcfe amounts)
Operating Revenues: |  |  |  |  |
Gas (includes transfers to operations of $1,379, $1,557 and $1,957, respectively)(1) | $ | 1,104,283 |  |  | $ | 738,778 |  |  | $ | 1,036,499 |
Oil, Condensate and Other Liquids | 1,837 |  |  | 2,298 |  |  | 2,261 |
Total Operating Revenues(2) | 1,106,120 |  |  | 741,076 |  |  | 1,038,760 |
Production/Lifting Costs | 284,771 |  |  | 270,927 |  |  | 253,555 |
Franchise/Ad Valorem Taxes | 18,267 |  |  | 13,468 |  |  | 17,532 |
Accretion Expense | 7,721 |  |  | 5,992 |  |  | 5,673 |
Depreciation, Depletion and Amortization ($0.61, $0.69 and $0.63 per Mcfe of production, respectively) | 261,712 |  |  | 270,648 |  |  | 235,694 |
Impairment of Exploration and Production Properties | 108,348 |  |  | 463,692 |  |  | — |
Income Tax Expense (Benefit) | 114,502 |  |  | (76,983) |  |  | 145,574 |
Results of Operations for Producing Activities (excluding corporate overheads and interest charges) | $ | 310,799 |  |  | $ | (206,668) |  |  | $ | 380,732 |
(1)There were no revenues from sales to affiliates for all years presented. (2)Exclusive of hedging gains and losses. See further discussion in Note J — Financial Instruments. Reserve Quantity Information The Company’s proved reserve estimates are prepared by the Company’s petroleum engineers who meet the qualifications of Reserve Estimator per the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information” promulgated by the Society of Petroleum Engineers as of June 25, 2019. The Company maintains comprehensive internal reserve guidelines and a continuing education program designed to keep its staff up to date with current SEC regulations and guidance. The Company’s Vice President of Reservoir Engineering is the primary technical person responsible for overseeing the Company’s reserve estimation process and engaging and overseeing the third party reserve audit. His qualifications include a Bachelor of Science Degree in Petroleum Engineering and over 15 years of Petroleum Engineering experience with independent oil and gas companies, licensure as a Professional Engineer and is a member of the Society of Petroleum Engineers. The Company maintains a system of internal controls over the reserve estimation process. Management reviews the price, heat content, lease operating cost and future investment assumptions used in the economic model to determine the reserves. The Vice President of Reservoir Engineering reviews and approves all new reserve assignments and significant reserve revisions. Access to the reserve database is restricted. Significant changes to the reserve report are reviewed by senior management on a quarterly basis. Periodically, the Company’s internal audit department assesses the design of these controls and performs testing to determine the effectiveness of such controls. All of the Company’s reserve estimates are audited annually by Netherland, Sewell & Associates, Inc. (NSAI). Since 1961, NSAI has evaluated gas and oil properties and independently certified petroleum reserve quantities in the United States and internationally under the Texas Board of Professional Engineers Registration No. F-002699. The primary technical persons (employed by NSAI) that are responsible for leading the audit include a professional engineer registered with the State of Texas (consulting at NSAI since 2019 and with over 6 years of prior industry experience in petroleum engineering) and a professional geoscientist registered in the State of Texas (consulting at NSAI since 2008 and with over 11 years of prior industry experience in petroleum geosciences). NSAI was satisfied with the methods and procedures used by the Company to prepare its reserve estimates at September 30, 2025 and did not identify any problems which would cause it to take exception to those estimates. The reliable technologies that were utilized in estimating the reserves include wire line open-hole log data, performance data, log cross sections, core data, 2D and 3D seismic data and statistical analysis. The statistical method utilized production performance from both the Company’s and competitors’ wells. Geophysical data includes data from the Company’s wells, third-party wells, published documents and state data-sites, and 2D and 3D seismic data. These were used to confirm continuity of the formation.
| U.S.
| Appalachian Region
| Gas MMcf |  |  |  | Oil Mbbl
Proved Developed and Undeveloped Reserves: |  |  |  |  |
September 30, 2022 | 4,170,662 |  |  |  |  | 250 |
Extensions and Discoveries | 670,438 |  | (1) |  |  | — |
Revisions of Previous Estimates | 32,379 |  |  |  |  | (4) |
Production | (372,271) |  | (2) |  |  | (30) |
Purchases of Minerals in Place | 33,876 |  |  |  |  | — |
September 30, 2023 | 4,535,084 |  |  |  |  | 216 |
Extensions and Discoveries | 601,679 |  | (1) |  |  | — |
Revisions of Previous Estimates | 7,046 |  |  |  |  | 8 |
Production | (392,047) |  | (2) |  |  | (31) |
September 30, 2024 | 4,751,762 |  |  |  |  | 193 |
Extensions and Discoveries | 632,536 |  | (1) |  |  | — |
Revisions of Previous Estimates | 22,469 |  |  |  |  | 15 |
Production | (426,357) |  | (2) |  |  | (28) |
September 30, 2025 | 4,980,410 |  |  |  |  | 180 |
Proved Developed Reserves: |  |  |  |  |
September 30, 2022 | 3,312,568 |  |  |  |  | 250 |
September 30, 2023 | 3,550,034 |  |  |  |  | 216 |
September 30, 2024 | 3,484,852 |  |  |  |  | 193 |
September 30, 2025 | 3,664,381 |  |  |  |  | 180 |
Proved Undeveloped Reserves: |  |  |  |  |
September 30, 2022 | 858,094 |  |  |  |  | — |
September 30, 2023 | 985,050 |  |  |  |  | — |
September 30, 2024 | 1,266,910 |  |  |  |  | — |
September 30, 2025 | 1,316,029 |  |  |  |  | — |
(1)Extensions and discoveries include 163 Bcf (during 2023), 230 Bcf (during 2024) and 0 Bcf (during 2025), of Marcellus Shale gas (which exceed 15% of total reserves) in the Appalachian region. Extensions and discoveries include 507 Bcf (during 2023), 372 Bcf (during 2024) and 633 Bcf (during 2025), of Utica Shale gas (which exceed 15% of total reserves) in the Appalachian region. (2)Production includes 190,290 MMcf (during 2023), 235,955 MMcf (during 2024) and 209,379 MMcf (during 2025), from Marcellus Shale fields. Production includes 180,750 MMcf (during 2023), 154,701 MMcf (during 2024) and 215,681 MMcf (during 2025), from Utica Shale fields. The Company’s proved undeveloped (PUD) reserves increased from 1,267 Bcfe at September 30, 2024 to 1,316 Bcfe at September 30, 2025. PUD reserves in the Utica Shale increased from 925 Bcfe at September 30, 2024 to 1,119 Bcfe at September 30, 2025. PUD reserves in the Marcellus Shale decreased from 342 Bcfe at September 30, 2024 to 197 Bcfe at September 30, 2025. The Company’s total PUD reserves were 26.4% of total proved reserves at September 30, 2025, down from 26.7% of total proved reserves at September 30, 2024. The Company’s PUD reserves increased from 985 Bcfe at September 30, 2023 to 1,267 Bcfe at September 30, 2024. PUD reserves in the Utica Shale increased from 873 Bcfe at September 30, 2023 to 925 Bcfe at September 30, 2024. PUD reserves in the Marcellus Shale increased from 112 Bcfe at September 30, 2023 to 342 Bcfe at September 30, 2024. The Company’s total PUD reserves were 26.7% of total proved reserves at September 30, 2024, up from 21.7% of total proved reserves at September 30, 2023. The increase in PUD reserves in 2025 of 49 Bcfe is a result of 473 Bcfe in new PUD reserve additions. These additions were partially offset by 399 Bcfe in PUD conversions to developed reserves (145 Bcfe from the Marcellus Shale and 254 Bcfe from the Utica Shale), 18 Bcfe in PUD reserves removed for one PUD location due to schedule and pad layout changes and 7 Bcfe for adjustments to remaining PUD reserves. The increase in PUD reserves in 2024 of 282 Bcfe is a result of 602 Bcfe in new PUD reserve additions and 76 Bcfe in upward revisions to remaining PUD reserves. These upward revisions were partially offset by 291 Bcfe in PUD conversions to developed reserves (all Utica Shale), and 105 Bcfe in PUD reserves removed for nine PUD locations due to schedule and pad layout changes. The Company invested $246 million during the year ended September 30, 2025 to convert 399 Bcfe (415 Bcfe after revisions) of predominantly Marcellus and Utica Shale PUD reserves to developed reserves. This represents 31% of the net PUD reserves recorded at September 30, 2024. The Company developed 27 of 73 PUD locations in 2025. The Company invested $306 million during the year ended September 30, 2024 to convert 291 Bcfe (374 Bcfe after revisions) of predominantly Marcellus and Utica Shale PUD reserves to developed reserves. This represents 30% of the net PUD reserves recorded at September 30, 2023. The Company developed 20 of 73 PUD locations in 2024. In 2026, the Company estimates that it will invest approximately $295 million to develop its PUD reserves. The Company is committed to developing its PUD reserves within five years as required by the SEC’s final rule on Modernization of Oil and Gas Reporting. Since that rule was adopted, and over the last five years, the Company developed 34% of its beginning year PUD reserves in fiscal 2021, 45% of its beginning year PUD reserves in fiscal 2022, 47% of its beginning year PUD reserves in fiscal 2023, 30% of its beginning year PUD reserves in fiscal 2024 and 31% of its beginning year PUD reserves in fiscal 2025. At September 30, 2025, the Company does not have any proved undeveloped reserves that have been on the books for more than five years at the corporate level, country level or field level. All of the Company’s proved reserves are in the United States. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves The Company cautions that the following presentation of the standardized measure of discounted future net cash flows is intended to be neither a measure of the fair market value of the Company’s exploration and production properties, nor an estimate of the present value of actual future cash flows to be obtained as a result of their development and production. It is based upon subjective estimates of proved reserves only and attributes no value to categories of reserves other than proved reserves, such as probable or possible reserves, or to unproved acreage. Furthermore, in accordance with the SEC’s final rule on Modernization of Oil and Gas Reporting, it is based on the unweighted arithmetic average of first day of the month commodity price for each month within the twelve-month period prior to the end of the reporting period and costs adjusted only for existing contractual changes. It assumes an arbitrary discount rate of 10%. Thus, it gives no effect to future price and cost changes certain to occur under widely fluctuating political and economic conditions. The standardized measure is intended instead to provide a means for comparing the value of the Company’s proved reserves at a given time with those of other exploration and production companies than is provided by a simple comparison of raw proved reserve quantities.
| Year Ended September 30
| 2025 |  | 2024 |  | 2023
| (Thousands)
United States |  |  |  |  |
Future Cash Inflows | $ | 12,243,757 |  |  | $ | 8,514,126 |  |  | $ | 11,947,345 |
Less: |  |  |  |  |
Future Production Costs | 3,823,175 |  |  | 3,672,901 |  |  | 3,538,389 |
Future Development Costs | 1,239,386 |  |  | 1,191,708 |  |  | 1,095,096 |
Future Income Tax Expense at Applicable Statutory Rate | 1,719,387 |  |  | 826,094 |  |  | 1,867,457 |
Future Net Cash Flows | 5,461,809 |  |  | 2,823,423 |  |  | 5,446,403 |
Less: |  |  |  |  |
10% Annual Discount for Estimated Timing of Cash Flows | 2,707,425 |  |  | 1,486,968 |  |  | 2,874,295 |
Standardized Measure of Discounted Future Net Cash Flows | $ | 2,754,384 |  |  | $ | 1,336,455 |  |  | $ | 2,572,108 |
The principal sources of change in the standardized measure of discounted future net cash flows were as follows:
| Year Ended September 30
| 2025 |  | 2024 |  | 2023
| (Thousands)
United States |  |  |  |  |
Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year | $ | 1,336,455 |  |  | $ | 2,572,108 |  |  | $ | 5,448,330 |
Sales, Net of Production Costs | (802,983) |  |  | (456,506) |  |  | (767,487) |
Net Changes in Prices, Net of Production Costs | 1,716,936 |  |  | (1,829,714) |  |  | (3,918,392) |
Extensions and Discoveries | 330,925 |  |  | (11,007) |  |  | 237,057 |
Changes in Estimated Future Development Costs | 58,606 |  |  | 32,990 |  |  | (222,233) |
Purchases of Minerals in Place | — |  |  | — |  |  | 34,346 |
Sales of Minerals in Place | — |  |  | — |  |  | — |
Previously Estimated Development Costs Incurred | 246,309 |  |  | 305,602 |  |  | 342,024 |
Net Change in Income Taxes at Applicable Statutory Rate | (467,758) |  |  | 462,075 |  |  | 959,728 |
Revisions of Previous Quantity Estimates | (7,374) |  |  | 19,216 |  |  | 33,192 |
Accretion of Discount and Other | 343,268 |  |  | 241,691 |  |  | 425,543 |
Standardized Measure of Discounted Future Net Cash Flows at End of Year | $ | 2,754,384 |  |  | $ | 1,336,455 |  |  | $ | 2,572,108 |

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- Definition The entire disclosure for oil- and gas-producing activities considered to be supplementary information. Includes, but is not limited to, proved reserve quantity, cost incurred and capitalized, result of operation, standardized measure, and change in standardized measure of discounted future cash flow. + References Reference 1: http://www.xbrl.org/2003/role/disclosureRef -Topic 932 -SubTopic 270 -Name Accounting Standards Codification -Section 50 -Paragraph 1 -Publisher FASB -URI https://asc.fasb.org/1943274/2147478688/932-270-50-1 Reference 2: http://www.xbrl.org/2003/role/disclosureRef -Topic 932 -SubTopic 235 -Name Accounting Standards Codification -Section 50 -Paragraph 10 -Publisher FASB -URI https://asc.fasb.org/1943274/2147477215/932-235-50-10 Reference 3: http://www.xbrl.org/2003/role/disclosureRef -Topic 932 -SubTopic 235 -Name Accounting Standards Codification -Section S99 -Paragraph 1 -Subparagraph (SAB Topic 12.A.3.e) -Publisher FASB -URI https://asc.fasb.org/1943274/2147477759/932-235-S99-1 Reference 4: http://www.xbrl.org/2003/role/disclosureRef -Topic 932 -SubTopic 235 -Name Accounting Standards Codification -Section S50 -Paragraph 3 -Publisher FASB -URI https://asc.fasb.org/1943274/2147479097/932-235-S50-3 Reference 5: http://www.xbrl.org/2003/role/disclosureRef -Topic 932 -SubTopic 235 -Name Accounting Standards Codification -Section 50 -Paragraph 8 -Subparagraph (c)(2) -Publisher FASB -URI https://asc.fasb.org/1943274/2147477215/932-235-50-8 Reference 6: http://www.xbrl.org/2003/role/disclosureRef -Topic 932 -Name Accounting Standards Codification -Publisher FASB -URI https://asc.fasb.org/932/tableOfContent Reference 7: http://www.xbrl.org/2003/role/disclosureRef -Topic 932 -SubTopic 235 -Name Accounting Standards Codification -Section 50 -Paragraph 1C -Publisher FASB -URI https://asc.fasb.org/1943274/2147477215/932-235-50-1C Reference 8: http://www.xbrl.org/2003/role/disclosureRef -Topic 932 -SubTopic 235 -Name Accounting Standards Codification -Section 50 -Paragraph 36 -Publisher FASB -URI https://asc.fasb.org/1943274/2147477215/932-235-50-36 Reference 9: http://www.xbrl.org/2003/role/disclosureRef -Topic 932 -SubTopic 235 -Name Accounting Standards Codification -Section 50 -Paragraph 8 -Subparagraph (c)(1) -Publisher FASB -URI https://asc.fasb.org/1943274/2147477215/932-235-50-8 Reference 10: http://www.xbrl.org/2003/role/disclosureRef -Topic 932 -SubTopic 235 -Name Accounting Standards Codification -Section 50 -Paragraph 5 -Publisher FASB -URI https://asc.fasb.org/1943274/2147477215/932-235-50-5 + Details
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