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.

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 2025. It expects the majority of its development and exploration costs associated with unproved properties to be transferred into the amortization base by 2023. Following is a summary of costs excluded from amortization at September 30, 2020:


	Total as of September 30, 2020		Year Costs Incurred
			2020		2019		2018		Prior
	(Thousands)
Acquisition Costs	$	64,218	$	39,953	$	—	$	—	$	24,265
Development Costs	75,138		54,761		17,326		403		2,648
Exploration Costs	7,606		—		—		—		7,606
Capitalized Interest	1,113		969		41		—		103
	$	148,075	$	95,683	$	17,367	$	403	$	34,622


	Year Ended September 30
	2020		2019		2018
	(Thousands)
United States
Property Acquisition Costs:
Proved	$	245,976	$	3,136	$	1,544
Unproved	42,922		3,679		4,286
Exploration Costs	3,891		2,060		29,365
Development Costs(1)	355,742		468,498		332,496
Asset Retirement Costs	62,080		26,192		(10,107)
	$	710,611	$	503,565	$	357,584


	Year Ended September 30
	2020		2019		2018
United States	(Thousands, except per Mcfe amounts)
Operating Revenues:
Gas (includes transfers to operations of 1,921, 2,532 and 2,134, respectively)(1)	$	402,447	$	481,048	$	390,642
Oil, Condensate and Other Liquids	107,844		149,078		168,254
Total Operating Revenues(2)	510,291		630,126		558,896
Production/Lifting Costs	203,670		186,626		162,721
Franchise/Ad Valorem Taxes	15,582		17,673		14,355
Purchased Emission Allowance Expense	2,930		2,527		1,883
Accretion Expense	5,237		3,723		4,266
Depreciation, Depletion and Amortization ($0.69, $0.71 and $0.67 per Mcfe of production, respectively)	166,759		149,881		119,946
Impairment of Oil and Gas Producing Properties	449,438		—		—
Income Tax Expense	(92,820)		64,652		72,723
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)	$	(240,505)	$	205,044	$	183,002

The Company's proved oil and gas reserve estimates are prepared by the Company's reservoir 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 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 30 years of Petroleum Engineering experience with both major and independent oil and gas companies. He has maintained oversight of the Company's reserve estimation process since 2003. He is a member of the Society of Petroleum Evaluation Engineers and a Registered Professional Engineer in the State of Texas.

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 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, 2020 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, 2017	1,926,614		46,506	1,973,120
Extensions and Discoveries	521,694	(1)	—	521,694
Revisions of Previous Estimates	90,113		3,322	93,435
Production	(160,499)	(2)	(2,407)	(162,906)

Sale of Minerals in Place	(57,420)		(10,581)	(68,001)
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
Proved Developed Reserves:
September 30, 2017	1,316,596		46,506	1,363,102
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
Proved Undeveloped Reserves:
September 30, 2017	610,018		—	610,018
September 30, 2018	750,810		—	750,810
September 30, 2019	1,014,724		—	1,014,724
September 30, 2020	551,262		—	551,262

(1)Extensions and discoveries include 274 Bcf (during 2018), 175 Bcf (during 2019) and 7 Bcf (during 2020), of Marcellus Shale gas (which exceed 15% of total reserves) in the Appalachian region. Extensions and discoveries include 248 Bcf (during 2018), 512 Bcf (during 2019) and 0 Bcf (during 2020), of Utica Shale gas (which exceed 15% of total reserves) in the Appalachian region.

(2)Production includes 150,196 MMcf (during 2018), 163,015 MMcf (during 2019) and 169,453 MMcf (during 2020), from Marcellus Shale fields. Production includes 9,409 MMcf (during 2018), 32,095 MMcf (during 2019) and 55,392 MMcf (during 2020), from Utica Shale fields.


	Oil Mbbl
	U.S.
	Appalachian Region	West Coast Region	Total Company
Proved Developed and Undeveloped Reserves:
September 30, 2017	28	30,179	30,207
Extensions and Discoveries	—	2,301	2,301
Revisions of Previous Estimates	(10)	2,487	2,477
Production	(4)	(2,531)	(2,535)
Sales of Minerals in Place	—	(4,787)	(4,787)


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
Proved Developed Reserves:
September 30, 2017	28	29,771	29,799
September 30, 2018	14	26,689	26,703
September 30, 2019	13	24,246	24,259
September 30, 2020	12	22,088	22,100
Proved Undeveloped Reserves:
September 30, 2017	—	408	408
September 30, 2018	—	960	960
September 30, 2019	—	614	614
September 30, 2020	—	—	—

The Company’s proved undeveloped (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 Company’s PUD reserves increased from 757 Bcfe at September 30, 2018 to 1,018 Bcfe at September 30, 2019. PUD reserves in the Marcellus Shale decreased slightly from 394 Bcfe at September 30, 2018 to 383 Bcfe at September 30, 2019. PUD reserves in the Utica Shale increased from 357 Bcfe at September 30, 2018 to 632 Bcfe at September 30, 2019. The Company’s total PUD reserves were 33% of total proved reserves at September 30, 2019, up from 30% of total proved reserves at September 30, 2018.

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

The increase in PUD reserves in 2019 of 261 Bcfe is a result of 575 Bcfe in new PUD reserve additions (175 Bcfe from the Marcellus Shale, 398 Bcfe from the Utica Shale and 2 Bcfe from the West Coast region) and 38 Bcfe in upward revisions to remaining PUD reserves, partially offset by 297 Bcfe in PUD conversions to developed reserves (186 Bcfe from the Marcellus Shale, 106 Bcfe from the Utica Shale and 5 Bcfe from the West Coast region), and 55 Bcfe in PUD reserves removed for six PUD locations, two of these wells removed are in the Marcellus (13 Bcfe) and four are in the Utica (42 Bcfe).

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.

The Company invested $246 million during the year ended September 30, 2019 to convert 297 Bcfe (380 Bcfe after positive revisions) of predominantly Marcellus and Utica Shale PUD reserves to developed reserves. This represents 39% of the net PUD reserves recorded at September 30, 2018. In fiscal 2019, the Company developed 56 (or 50%) of its well locations with net PUD reserves recorded at September 30, 2018. The majority of these wells were in the Appalachian region. The 83 Bcfe in upward revisions to PUD reserves converted to developed reserves in 2019 were a result of longer completed laterals and improved well performance at PUD locations that were recorded at September 30, 2019.

In 2021, the Company estimates that it will invest approximately $134 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 25% of its beginning year PUD reserves in fiscal 2016, 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 and 36% of its beginning year PUD reserves in fiscal 2020.

At September 30, 2020, 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
	2020		2019		2018
	(Thousands)
United States
Future Cash Inflows	$	6,493,362	$	8,738,182	$	7,822,855
Less:
Future Production Costs	3,149,857		2,989,518		2,606,411
Future Development Costs	501,678		797,640		559,707
Future Income Tax Expense at Applicable Statutory Rate	454,553		1,159,882		1,125,910
Future Net Cash Flows	2,387,274		3,791,142		3,530,827
Less:
10% Annual Discount for Estimated Timing of Cash Flows	1,164,804		2,054,823		1,810,522
Standardized Measure of Discounted Future Net Cash Flows	$	1,222,470	$	1,736,319	$	1,720,305


	Year Ended September 30
	2020		2019		2018
	(Thousands)
United States
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year	$	1,736,319	$	1,720,305	$	1,113,046
Sales, Net of Production Costs	(290,975)		(425,773)		(381,775)
Net Changes in Prices, Net of Production Costs	(1,109,101)		(164,428)		541,021
Extensions and Discoveries	4,236		202,683		212,494
Changes in Estimated Future Development Costs	99,884		(69,254)		(43,771)
Purchases of Minerals in Place	170,363		—		—
Sales of Minerals in Place	—		—		(100,816)
Previously Estimated Development Costs Incurred	219,938		245,964		182,348
Net Change in Income Taxes at Applicable Statutory Rate	248,182		21,370		55,558
Revisions of Previous Quantity Estimates	(28,337)		53,777		61,363
Accretion of Discount and Other	171,961		151,675		80,837
Standardized Measure of Discounted Future Net Cash Flows at End of Year	$	1,222,470	$	1,736,319	$	1,720,305