The following supplementary information is presented in accordance with the authoritative guidance regarding disclosures about oil and gas producing 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.

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 2028. 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, 2023:


	Total as of September 30, 2023		Year Costs Incurred
			2023		2022		2021		Prior
	(Thousands)
Acquisition Costs	$	143,860	$	120,349	$	—	$	—	$	23,511
Development Costs	17,207		8,034		3,001		3,704		2,468
Exploration Costs	—		—		—		—		—
Capitalized Interest	30		30		—		—		—
	$	161,097	$	128,413	$	3,001	$	3,704	$	25,979


	Year Ended September 30
	2023		2022		2021
	(Thousands)
United States
Property Acquisition Costs:
Proved	$	33,190	$	2,491	$	1,801
Unproved	129,061		10,665		5,102
Exploration Costs(1)	10,055		9,631		15,413
Development Costs(2)	553,469		528,684		329,368
Asset Retirement Costs	8,363		9,768		20,194
	$	734,138	$	561,239	$	371,878


	Year Ended September 30
	2023		2022		2021
United States	(Thousands, except per Mcfe amounts)
Operating Revenues:
Gas (includes transfers to operations of $1,957, $5,696 and $3,061, respectively)(1)	$	1,036,499	$	1,730,723	$	780,477
Oil, Condensate and Other Liquids	2,261		150,957		135,191
Total Operating Revenues(2)	1,038,760		1,881,680		915,668
Production/Lifting Costs	253,555		283,914		267,316
Franchise/Ad Valorem Taxes	17,532		25,112		22,128
Purchased Emission Allowance Expense	—		1,305		2,940
Accretion Expense	5,673		7,530		7,743
Depreciation, Depletion and Amortization ($0.63, $0.57 and $0.54 per Mcfe of production, respectively)	235,694		202,418		177,055
Impairment of Oil and Gas Producing Properties	—		—		76,152
Income Tax Expense	145,574		368,925		98,593
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)	$	380,732	$	992,476	$	263,741

The Company's proved oil and gas 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 14 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, 2023 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, 2020	3,296,113		28,972	3,325,085
Extensions and Discoveries	689,395	(1)	—	689,395
Revisions of Previous Estimates	19,940		3,033	22,973
Production	(312,300)	(2)	(1,720)	(314,020)


September 30, 2021	3,693,148		30,285	3,723,433
Extensions and Discoveries	837,510	(1)	—	837,510
Revisions of Previous Estimates	2,882		71	2,953
Production	(341,700)	(2)	(1,211)	(342,911)

Sale of Minerals in Place	(21,178)		(29,145)	(50,323)
September 30, 2022	4,170,662		—	4,170,662
Extensions and Discoveries	670,438	(1)	—	670,438
Revisions of Previous Estimates	32,379		—	32,379
Production	(372,271)	(2)	—	(372,271)

Purchases of Minerals in Place	33,876		—	33,876
September 30, 2023	4,535,084		—	4,535,084
Proved Developed Reserves:
September 30, 2020	2,744,851		28,972	2,773,823
September 30, 2021	3,061,178		30,285	3,091,463
September 30, 2022	3,312,568		—	3,312,568
September 30, 2023	3,550,034		—	3,550,034
Proved Undeveloped Reserves:
September 30, 2020	551,262		—	551,262
September 30, 2021	631,970		—	631,970
September 30, 2022	858,094		—	858,094
September 30, 2023	985,050		—	985,050

(1)Extensions and discoveries include 180 Bcf (during 2021), 301 Bcf (during 2022) and 163 Bcf (during 2023), of Marcellus Shale gas (which exceed 15% of total reserves) in the Appalachian region. Extensions and discoveries include 497 Bcf (during 2021), 537 Bcf (during 2022) and 507 Bcf (during 2023), of Utica Shale gas (which exceed 15% of total reserves) in the Appalachian region.

(2)Production includes 218,016 MMcf (during 2021), 209,463 MMcf (during 2022) and 190,290 MMcf (during 2023), from Marcellus Shale fields. Production includes 93,253 MMcf (during 2021), 130,240 MMcf (during 2022) and 180,750 MMcf (during 2023), from Utica Shale fields.


	Oil Mbbl
	U.S.
	Appalachian Region	West Coast Region	Total Company
Proved Developed and Undeveloped Reserves:
September 30, 2020	12	22,088	22,100
Extensions and Discoveries	—	1,041	1,041
Revisions of Previous Estimates	1	630	631
Production	(2)	(2,233)	(2,235)



September 30, 2021	11	21,526	21,537
Extensions and Discoveries	—	296	296
Revisions of Previous Estimates	255	532	787
Production	(16)	(1,588)	(1,604)

Sales of Minerals in Place	—	(20,766)	(20,766)
September 30, 2022	250	—	250

Revisions of Previous Estimates	(4)	—	(4)
Production	(30)	—	(30)


September 30, 2023	216	—	216
Proved Developed Reserves:
September 30, 2020	12	22,088	22,100
September 30, 2021	11	20,930	20,941
September 30, 2022	250	—	250
September 30, 2023	216	—	216
Proved Undeveloped Reserves:
September 30, 2020	—	—	—
September 30, 2021	—	596	596
September 30, 2022	—	—	—
September 30, 2023	—	—	—

The Company’s proved undeveloped (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 Company’s PUD reserves increased from 636 Bcfe at September 30, 2021 to 858 Bcfe at September 30, 2022. PUD reserves in the Utica Shale increased from 411 Bcfe at September 30, 2021 to 503 Bcfe at September 30, 2022. PUD reserves in the Marcellus Shale increased from 220 Bcfe at September 30, 2021 to 355 Bcfe at September 30, 2022. PUD reserves in the West Coast region decreased from 5 Bcfe at September 30, 2021 to zero at September 30, 2022. The Company’s total PUD reserves were 20.6% of total proved reserves at September 30, 2022, up from 16.5% of total proved reserves at September 30, 2021.

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 increase in PUD reserves in 2022 of 222 Bcfe is a result of 502 Bcfe in new PUD reserve additions and 23 Bcfe in upward revisions to remaining PUD reserves, partially offset by 287 Bcfe in PUD conversions to developed reserves (55 Bcfe from the Marcellus Shale, 231 Bcfe from the Utica Shale and 1 Bcfe from the West Coast region), and 13 Bcfe in PUD reserves removed for one Utica PUD location due to pad layout changes. The remaining change of 3 Bcf was due to removing West Coast region PUDs included in the beginning of year balances through development and divesture of Seneca's California assets.

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.

The Company invested $154 million during the year ended September 30, 2022 to convert 287 Bcfe (333 Bcfe after revisions) of predominantly Marcellus and Utica Shale PUD reserves to developed reserves. This represents 45% of the net PUD reserves recorded at September 30, 2021. In the Appalachian region, 31 of 65 PUD locations were developed while the West Coast region developed 6 of 17 PUD locations prior to the divesture. PUD expenditures in 2022 were lower than the 2021 estimate primarily due to changes in the development schedule.

In 2024, the Company estimates that it will invest approximately $315 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 39% of its beginning year PUD reserves in fiscal 2019, 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 and 47% of its beginning year PUD reserves in fiscal 2023.

At September 30, 2023, 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.

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 oil and gas 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 the first day of the month oil and gas prices 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 oil- and gas-producing companies than is provided by a simple comparison of raw proved reserve quantities.


	Year Ended September 30
	2023		2022		2021
	(Thousands)
United States
Future Cash Inflows	$	11,947,345	$	19,209,099	$	10,175,182
Less:
Future Production Costs	3,538,389		3,138,226		3,423,629
Future Development Costs	1,095,096		781,847		597,662
Future Income Tax Expense at Applicable Statutory Rate	1,867,457		3,876,272		1,397,175
Future Net Cash Flows	5,446,403		11,412,754		4,756,716
Less:
10% Annual Discount for Estimated Timing of Cash Flows	2,874,295		5,964,424		2,403,144
Standardized Measure of Discounted Future Net Cash Flows	$	2,572,108	$	5,448,330	$	2,353,572


	Year Ended September 30
	2023		2022		2021
	(Thousands)
United States

Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year	$	5,448,330	$	2,353,572	$	1,222,470
Sales, Net of Production Costs	(767,487)		(1,572,402)		(626,132)
Net Changes in Prices, Net of Production Costs	(3,918,392)		4,132,889		1,478,995
Extensions and Discoveries	237,057		1,355,257		462,040
Changes in Estimated Future Development Costs	(222,233)		(32,160)		48,247
Purchases of Minerals in Place	34,346		—		—
Sales of Minerals in Place	—		(311,308)		—
Previously Estimated Development Costs Incurred	342,024		154,253		81,239
Net Change in Income Taxes at Applicable Statutory Rate	959,728		(1,180,349)		(415,993)
Revisions of Previous Quantity Estimates	33,192		3,316		(52,383)
Accretion of Discount and Other	425,543		545,262		155,089
Standardized Measure of Discounted Future Net Cash Flows at End of Year	$	2,572,108	$	5,448,330	$	2,353,572