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Supplementary Information for Exploration and Production Activities
 12 Months Ended
Sep. 30, 2024
Supplementary Information for Exploration and Production Activities Unaudited [Abstract]  
Supplementary Information for Exploration and Production Activities (unaudited, except for Capitalized Costs Relating to 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. As discussed in Note B — Asset Acquisitions and Divestitures, the Company completed the sale of its California
assets on June 30, 2022. With the completion of this sale, the Company no longer has any oil or gas reserves in the West Coast region of the U.S.
Capitalized Costs Relating to Exploration and Production Activities
 At September 30
 20242023
 (Thousands)
Proved Properties(1)$7,079,903 $6,555,088 
Unproved Properties200,986 161,097 
7,280,889 6,716,185 
Less — Accumulated Depreciation, Depletion and Amortization5,004,299 4,269,959 
$2,276,590 $2,446,226 
(1)Includes asset retirement costs of $175.2 million and $129.2 million at September 30, 2024 and 2023, 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 2029. It expects the majority of its development and exploration costs associated with unproved properties to be transferred into the amortization base by 2026. Following is a summary of costs excluded from amortization at September 30, 2024:
 
Total as of
September 30,
2024
Year Costs Incurred
202420232022Prior
 (Thousands)
Acquisition Costs$140,753 $8,136 $104,858 $2,072 $25,687 
Development Costs48,642 46,597 1,821 185 39 
Exploration Costs10,813 10,813 — — — 
Capitalized Interest778 778 — — — 
$200,986 $66,324 $106,679 $2,257 $25,726 
Costs Incurred in Property Acquisition, Exploration and Development Activities
 Year Ended September 30
 202420232022
 (Thousands)
United States
Property Acquisition Costs:
Proved$17,069 $33,190 $2,491 
Unproved19,526 129,061 10,665 
Exploration Costs(1)53,519 10,055 9,631 
Development Costs(2)429,151 553,469 528,684 
Asset Retirement Costs46,017 8,363 9,768 
$565,282 $734,138 $561,239 
(1)Amounts for 2024, 2023 and 2022 include capitalized interest of $0.1 million, zero and zero  respectively.
(2)Amounts for 2024, 2023 and 2022 include capitalized interest of $0.7 million, $0.1 million and $0.6 million, respectively.
For the years ended September 30, 2024, 2023 and 2022, the Company spent $305.6 million, $342.0 million and $154.3 million, respectively, developing proved undeveloped reserves.
Results of Operations for Producing Activities
 Year Ended September 30
 202420232022
United States(Thousands, except per Mcfe amounts)
Operating Revenues:
Gas (includes transfers to operations of $1,557, $1,957 and $5,696, respectively)(1)
$738,778 $1,036,499 $1,730,723 
Oil, Condensate and Other Liquids2,298 2,261 150,957 
Total Operating Revenues(2)741,076 1,038,760 1,881,680 
Production/Lifting Costs270,927 253,555 283,914 
Franchise/Ad Valorem Taxes13,468 17,532 25,112 
Purchased Emission Allowance Expense— — 1,305 
Accretion Expense5,992 5,673 7,530 
Depreciation, Depletion and Amortization ($0.69, $0.63 and $0.57 per Mcfe of production, respectively)
270,648 235,694 202,418 
Impairment of Exploration and Production Properties463,692 — — 
Income Tax Expense (Benefit)(76,983)145,574 368,925 
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)
$(206,668)$380,732 $992,476 
(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, 2024 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.
 Gas MMcf
 U.S. 
 Appalachian
Region		 West Coast
Region		Total
Company
Proved Developed and Undeveloped Reserves:
September 30, 20213,693,148   30,285 3,723,433 
Extensions and Discoveries837,510 (1)— 837,510 
Revisions of Previous Estimates2,882 71 2,953 
Production(341,700)(2)(1,211)(342,911)
Sale of Minerals in Place(21,178)(29,145)(50,323)
September 30, 20224,170,662   — 4,170,662 
Extensions and Discoveries670,438 (1)— 670,438 
Revisions of Previous Estimates32,379 — 32,379 
Production(372,271)(2)— (372,271)
Purchases of Minerals in Place33,876 — 33,876 
September 30, 20234,535,084   — 4,535,084 
Extensions and Discoveries601,679 (1)— 601,679 
Revisions of Previous Estimates7,046   — 7,046 
Production(392,047)(2)— (392,047)
September 30, 20244,751,762   — 4,751,762 
Proved Developed Reserves:
September 30, 20213,061,178 30,285 3,091,463 
September 30, 20223,312,568 — 3,312,568 
September 30, 20233,550,034 — 3,550,034 
September 30, 20243,484,852   — 3,484,852 
Proved Undeveloped Reserves:
September 30, 2021631,970 — 631,970 
September 30, 2022858,094 — 858,094 
September 30, 2023985,050 — 985,050 
September 30, 20241,266,910   — 1,266,910 
(1)Extensions and discoveries include 301 Bcf (during 2022), 163 Bcf (during 2023) and 230 Bcf (during 2024), of Marcellus Shale gas (which exceed 15% of total reserves) in the Appalachian region. Extensions and discoveries include 537 Bcf (during 2022), 507 Bcf (during 2023) and 372 Bcf (during 2024), of Utica Shale gas (which exceed 15% of total reserves) in the Appalachian region.
(2)Production includes 209,463 MMcf (during 2022), 190,290 MMcf (during 2023) and 235,955 MMcf (during 2024), from Marcellus Shale fields. Production includes 130,240 MMcf (during 2022), 180,750 MMcf (during 2023) and 154,701 MMcf (during 2024), from Utica Shale fields.
 Oil Mbbl
 U.S. 
 Appalachian
Region		West Coast
Region		Total
Company
Proved Developed and Undeveloped Reserves:
September 30, 202111 21,526 21,537 
Extensions and Discoveries— 296 296 
Revisions of Previous Estimates255 532 787 
Production(16)(1,588)(1,604)
Sales of Minerals in Place— (20,766)(20,766)
September 30, 2022250 — 250 
Revisions of Previous Estimates(4)— (4)
Production(30)— (30)
September 30, 2023216 — 216 
Revisions of Previous Estimates8 — 8 
Production(31)— (31)
September 30, 2024193 — 193 
Proved Developed Reserves:
September 30, 202111 20,930 20,941 
September 30, 2022250 — 250 
September 30, 2023216 — 216 
September 30, 2024193 — 193 
Proved Undeveloped Reserves:
September 30, 2021— 596 596 
September 30, 2022— — — 
September 30, 2023— — — 
September 30, 2024— — — 
The Company’s proved undeveloped (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 Company’s PUD reserves increased from 858 Bcfe at September 30, 2022 to 985 Bcfe at September 30, 2023. PUD reserves in the Utica Shale increased from 503 Bcfe at September 30, 2022 to 873 Bcfe at September 30, 2023. PUD reserves in the Marcellus Shale decreased from 355 Bcfe at September 30, 2022 to 112 Bcfe at September 30, 2023. The Company’s total PUD reserves were 21.7% of total proved reserves at September 30, 2023, up from 20.6% of total proved reserves at September 30, 2022.
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 increase in PUD reserves in 2023 of 127 Bcfe is a result of 554 Bcfe in new PUD reserve additions, 14 Bcfe for one PUD well added back into the schedule and 23 Bcfe in upward revisions to remaining PUD reserves. These upward revisions were partially offset by 402 Bcfe in PUD conversions to developed reserves
(275 Bcfe from the Marcellus Shale and 127 Bcfe from the Utica Shale), and 62 Bcfe in PUD reserves removed for seven PUD locations due to schedule and pad layout changes.
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.
The Company invested $342 million during the year ended September 30, 2023 to convert 402 Bcfe (440 Bcfe after revisions) of predominantly Marcellus and Utica Shale PUD reserves to developed reserves. This represents 47% of the net PUD reserves recorded at September 30, 2022. The Company developed 39 of 77 PUD locations in 2023. PUD expenditures in 2023 were higher than the 2022 estimate due to schedule changes and changes in service costs.
In 2025, the Company estimates that it will invest approximately $300 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 36% of its beginning year PUD reserves in fiscal 2020, 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 and 30% of its beginning year PUD reserves in fiscal 2024.
At September 30, 2024, 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
 202420232022
 (Thousands)
United States
Future Cash Inflows$8,514,126 $11,947,345 $19,209,099 
Less:
Future Production Costs3,672,901 3,538,389 3,138,226 
Future Development Costs1,191,708 1,095,096 781,847 
Future Income Tax Expense at Applicable Statutory Rate826,094 1,867,457 3,876,272 
Future Net Cash Flows2,823,423 5,446,403 11,412,754 
Less:
10% Annual Discount for Estimated Timing of Cash Flows1,486,968 2,874,295 5,964,424 
Standardized Measure of Discounted Future Net Cash Flows$1,336,455 $2,572,108 $5,448,330 
The principal sources of change in the standardized measure of discounted future net cash flows were as follows:
 Year Ended September 30
 202420232022
 (Thousands)
United States
Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year$2,572,108 $5,448,330 $2,353,572 
Sales, Net of Production Costs(456,506)(767,487)(1,572,402)
Net Changes in Prices, Net of Production Costs(1,829,714)(3,918,392)4,132,889 
Extensions and Discoveries(11,007)237,057 1,355,257 
Changes in Estimated Future Development Costs32,990 (222,233)(32,160)
Purchases of Minerals in Place— 34,346 — 
Sales of Minerals in Place— — (311,308)
Previously Estimated Development Costs Incurred305,602 342,024 154,253 
Net Change in Income Taxes at Applicable Statutory Rate462,075 959,728 (1,180,349)
Revisions of Previous Quantity Estimates19,216 33,192 3,316 
Accretion of Discount and Other241,691 425,543 545,262 
Standardized Measure of Discounted Future Net Cash Flows at End of Year
$1,336,455 $2,572,108 $5,448,330