The Company follows authoritative guidance related to oil and gas 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 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.

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. All monetary amounts are expressed in U.S. dollars.


	At September 30
	2021		2020
	(Thousands)
Proved Properties(1)	$	6,652,341	$	6,238,830
Unproved Properties	103,759		148,075
	6,756,100		6,386,905
Less — Accumulated Depreciation, Depletion and Amortization	4,881,972		4,628,765
	$	1,874,128	$	1,758,140

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 2026. It expects the majority of its development and exploration costs associated with unproved properties to be transferred into the amortization base by 2024. Following is a summary of costs excluded from amortization at September 30, 2021:


	Total as of September 30, 2021		Year Costs Incurred
			2021		2020		2019		Prior
	(Thousands)
Acquisition Costs	$	57,027	$	—	$	32,762	$	—	$	24,265
Development Costs	37,574		14,979		2,430		17,114		3,051
Exploration Costs	8,178		572		—		—		7,606
Capitalized Interest	980		340		496		41		103
	$	103,759	$	15,891	$	35,688	$	17,155	$	35,025


	Year Ended September 30
	2021		2020		2019
	(Thousands)
United States
Property Acquisition Costs:
Proved	$	1,801	$	245,976	$	3,136
Unproved	5,102		42,922		3,679
Exploration Costs(1)	15,413		3,891		2,060
Development Costs(2)	329,368		355,742		468,498
Asset Retirement Costs	20,194		62,080		26,192
	$	371,878	$	710,611	$	503,565


	Year Ended September 30
	2021		2020		2019
United States	(Thousands, except per Mcfe amounts)
Operating Revenues:
Gas (includes transfers to operations of $3,061, $1,921 and $2,532, respectively)(1)	$	780,477	$	402,447	$	481,048
Oil, Condensate and Other Liquids	135,191		107,844		149,078
Total Operating Revenues(2)	915,668		510,291		630,126
Production/Lifting Costs	267,316		203,670		186,626
Franchise/Ad Valorem Taxes	22,128		15,582		17,673
Purchased Emission Allowance Expense	2,940		2,930		2,527
Accretion Expense	7,743		5,237		3,723
Depreciation, Depletion and Amortization ($0.54, $0.69 and $0.71 per Mcfe of production, respectively)	177,055		166,759		149,881
Impairment of Oil and Gas Producing Properties	76,152		449,438		—
Income Tax Expense	98,593		(92,820)		64,652
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)	$	263,741	$	(240,505)	$	205,044

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 February 19, 2007. 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 Senior Manager 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 12 years of Petroleum Engineering experience with independent oil and gas companies 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 Senior Manager 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 and 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 2011 and with over

4 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, 2021 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, 2018	2,320,502		36,840	2,357,342
Extensions and Discoveries	686,549	(1)	—	686,549
Revisions of Previous Estimates	104,741		(1,233)	103,508
Production	(195,906)	(2)	(1,974)	(197,880)


September 30, 2019	2,915,886		33,633	2,949,519
Extensions and Discoveries	7,246	(1)	—	7,246
Revisions of Previous Estimates	(85,647)		(2,772)	(88,419)
Production	(225,513)	(2)	(1,889)	(227,402)
Purchases of Minerals in Place	684,141		—	684,141

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
Proved Developed Reserves:
September 30, 2018	1,569,692		36,840	1,606,532
September 30, 2019	1,901,162		33,633	1,934,795
September 30, 2020	2,744,851		28,972	2,773,823
September 30, 2021	3,061,178		30,285	3,091,463
Proved Undeveloped Reserves:
September 30, 2018	750,810		—	750,810
September 30, 2019	1,014,724		—	1,014,724
September 30, 2020	551,262		—	551,262
September 30, 2021	631,970		—	631,970

(1)Extensions and discoveries include 175 Bcf (during 2019), 7 Bcf (during 2020) and 180 Bcf (during 2021), of Marcellus Shale gas (which exceed 15% of total reserves) in the Appalachian region. Extensions and discoveries include 512 Bcf (during 2019), 0 Bcf (during 2020) and 497 Bcf (during 2021), of Utica Shale gas (which exceed 15% of total reserves) in the Appalachian region.

(2)Production includes 163,015 MMcf (during 2019), 169,453 MMcf (during 2020) and 218,016 MMcf (during 2021), from Marcellus Shale fields. Production includes 32,095 MMcf (during 2019), 55,392 MMcf (during 2020) and 93,253 MMcf (during 2021), from Utica Shale fields.


	Oil Mbbl
	U.S.
	Appalachian Region	West Coast Region	Total Company
Proved Developed and Undeveloped Reserves:
September 30, 2018	14	27,649	27,663
Extensions and Discoveries	—	787	787
Revisions of Previous Estimates	2	(1,256)	(1,254)
Production	(3)	(2,320)	(2,323)



September 30, 2019	13	24,860	24,873
Extensions and Discoveries	—	288	288
Revisions of Previous Estimates	2	(715)	(713)
Production	(3)	(2,345)	(2,348)


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
Proved Developed Reserves:
September 30, 2018	14	26,689	26,703
September 30, 2019	13	24,246	24,259
September 30, 2020	12	22,088	22,100
September 30, 2021	11	20,930	20,941
Proved Undeveloped Reserves:
September 30, 2018	—	960	960
September 30, 2019	—	614	614
September 30, 2020	—	—	—
September 30, 2021	—	596	596

The Company’s proved undeveloped (PUD) reserves increased from 551 Bcfe at September 30, 2020 to 636 Bcfe at September 30, 2021. PUD reserves in the Utica Shale increased from 265 Bcfe at September 30, 2020 to 411 Bcfe at September 30, 2021. PUD reserves in the Marcellus Shale decreased from 287 Bcfe at September 30, 2020 to 220 Bcfe at September 30, 2021. The Company’s total PUD reserves were 16.5% of total proved reserves at September 30, 2021, roughly flat from 16% of total proved reserves at September 30, 2020.

The Company’s PUD reserves decreased from 1,018 Bcfe at September 30, 2019 to 551 Bcfe at September 30, 2020. PUD reserves in the Marcellus Shale decreased from 383 Bcfe at September 30, 2019 to 287 Bcfe at September 30, 2020. PUD reserves in the Utica Shale decreased from 632 Bcfe at September 30, 2019 to 265 Bcfe at September 30, 2020. The Company’s total PUD reserves were 16% of total proved reserves at September 30, 2020, down from 33% of total proved reserves at September 30, 2019.

The increase in PUD reserves in 2021 of 85 Bcfe is a result of 344 Bcfe in new PUD reserve additions and 9 Bcfe in upward revisions to remaining PUD reserves, partially offset by 188 Bcfe in PUD conversions to developed reserves (82 Bcfe from the Marcellus Shale and 106 Bcfe from the Utica Shale), and 80 Bcfe in PUD

The decrease in PUD reserves in 2020 of 467 Bcfe is a result of 363 Bcfe in PUD conversions to developed reserves (146 Bcfe from the Marcellus Shale, 214 Bcfe from the Utica Shale and 3 Bcfe from the West Coast region), and 179 Bcfe in PUD reserves removed for seventeen PUD locations, all in the Western Development Area, due to development timing no longer scheduled to meet the five year requirement for proved reserves. Two of these wells removed were in the Marcellus Shale (14 Bcfe) and fifteen were in the Utica Shale (165 Bcfe). These decreases were offset by 7 Bcfe in new PUD reserve additions, 20 Bcfe in upward revisions to remaining PUD reserves and 48 Bcfe in revisions for five PUD locations added back in 2020 (after removing one in 2016 and four in 2017 due to scheduling delays beyond the five year requirement).

The Company invested $81 million during the year ended September 30, 2021 to convert 188 Bcfe (198 Bcfe after revisions) of predominantly Marcellus and Utica Shale PUD reserves to developed reserves. This represents 34% of the net PUD reserves recorded at September 30, 2020. In the Appalachian region, 18 of 53 PUD locations were developed. PUD expenditures in 2021 were lower than the 2020 estimate primarily due to changes in the development schedule.

The Company invested $220 million during the year ended September 30, 2020 to convert 363 Bcfe (393 Bcfe after revisions) of predominantly Marcellus and Utica Shale PUD reserves to developed reserves. This represents 36% of the net PUD reserves recorded at September 30, 2019. The 30 Bcfe in upward revisions to PUD reserves converted to developed reserves in 2020 were primarily a result of longer completed laterals. In the Appalachian region, 35 of 99 PUD locations were developed and in the West Coast region, all 14 PUD locations were developed.

In 2022, the Company estimates that it will invest approximately $161 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, and over the last five years, the Company developed 27% of its beginning year PUD reserves in fiscal 2017, 51% of its beginning year PUD reserves in fiscal 2018, 39% of its beginning year PUD reserves in fiscal 2019, 36% of its beginning year PUD reserves in fiscal 2020 and 34% of its beginning year PUD reserves in fiscal 2021.

At September 30, 2021, 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
	2021		2020		2019
	(Thousands)
United States
Future Cash Inflows	$	10,175,182	$	6,493,362	$	8,738,182
Less:
Future Production Costs	3,423,629		3,149,857		2,989,518
Future Development Costs	597,662		501,678		797,640
Future Income Tax Expense at Applicable Statutory Rate	1,397,175		454,553		1,159,882
Future Net Cash Flows	4,756,716		2,387,274		3,791,142
Less:
10% Annual Discount for Estimated Timing of Cash Flows	2,403,144		1,164,804		2,054,823
Standardized Measure of Discounted Future Net Cash Flows	$	2,353,572	$	1,222,470	$	1,736,319


	Year Ended September 30
	2021		2020		2019
	(Thousands)
United States
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year	$	1,222,470	$	1,736,319	$	1,720,305
Sales, Net of Production Costs	(626,132)		(290,975)		(425,773)
Net Changes in Prices, Net of Production Costs	1,478,995		(1,109,101)		(164,428)
Extensions and Discoveries	462,040		4,236		202,683
Changes in Estimated Future Development Costs	48,247		99,884		(69,254)
Purchases of Minerals in Place	—		170,363		—
Sales of Minerals in Place	—		—		—
Previously Estimated Development Costs Incurred	81,239		219,938		245,964
Net Change in Income Taxes at Applicable Statutory Rate	(415,993)		248,182		21,370
Revisions of Previous Quantity Estimates	(52,383)		(28,337)		53,777
Accretion of Discount and Other	155,089		171,961		151,675
Standardized Measure of Discounted Future Net Cash Flows at End of Year	$	2,353,572	$	1,222,470	$	1,736,319