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 2024. It expects the majority of its development and exploration costs associated with unproved properties to be transferred into the amortization base by 2022. Following is a summary of costs excluded from amortization at September 30, 2019:



	Total as of September 30, 2019		Year Costs Incurred
	Total as of September 30, 2019		2019		2018		2017		Prior
	(Thousands)
Acquisition Costs	$	24,265	$	—	$	—	$	—	$	24,265
Development Costs	21,483		17,819		481		43		3,140
Exploration Costs	7,606		—		—		32		7,574
Capitalized Interest	144		41		—		—		103
	$	53,498	$	17,860	$	481	$	75	$	35,082



	Year Ended September 30
	2019		2018			2017
	(Thousands)
United States
Property Acquisition Costs:
Proved	$	3,136	$	1,544		$	8,908
Unproved	3,679		4,286			262
Exploration Costs(1)	2,060		29,365			40,975
Development Costs(2)	468,498		332,496			200,639
Asset Retirement Costs	26,192		(10,107		)	(9,175		)
	$	503,565	$	357,584		$	241,609



	Year Ended September 30
	2019		2018		2017
United States	(Thousands, except per Mcfe amounts)
Operating Revenues:
Gas (includes transfers to operations of $2,532, $2,134 and $2,357, respectively)(1)	$	481,048	$	390,642	$	399,975
Oil, Condensate and Other Liquids	149,078		168,254		126,517
Total Operating Revenues(2)	630,126		558,896		526,492
Production/Lifting Costs	186,626		162,721		165,991
Franchise/Ad Valorem Taxes	17,673		14,355		15,372
Purchased Emission Allowance Expense	2,527		1,883		1,391
Accretion Expense	3,723		4,266		4,896
Depreciation, Depletion and Amortization ($0.71, $0.67 and $0.63 per Mcfe of production, respectively)	149,881		119,946		108,471
Income Tax Expense	64,652		72,723		86,657
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)	$	205,044	$	183,002	$	143,714

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, 2019 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, 2016	1,631,451			43,124		1,674,575
Extensions and Discoveries	386,649		(1)	8		386,657
Revisions of Previous Estimates	84,480			6,369		90,849
Production	(154,093	)	(2)	(2,995	)	(157,088	)
Sale of Minerals in Place	(21,873	)		—		(21,873	)
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
Proved Developed Reserves:
September 30, 2016	1,089,492			43,124		1,132,616
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
Proved Undeveloped Reserves:
September 30, 2016	541,959			—		541,959
September 30, 2017	610,018			—		610,018
September 30, 2018	750,810			—		750,810
September 30, 2019	1,014,724			—		1,014,724



	Oil Mbbl
	U.S.
	Appalachian Region		West Coast Region		Total Company
Proved Developed and Undeveloped Reserves:
September 30, 2016	73		28,936		29,009
Extensions and Discoveries	—		674		674
Revisions of Previous Estimates	(12	)	3,305		3,293
Production	(4	)	(2,736	)	(2,740	)
Sales of Minerals in Place	(29	)	—		(29	)
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
Proved Developed Reserves:
September 30, 2016	73		28,698		28,771
September 30, 2017	28		29,771		29,799
September 30, 2018	14		26,689		26,703
September 30, 2019	13		24,246		24,259
Proved Undeveloped Reserves:
September 30, 2016	—		238		238
September 30, 2017	—		408		408
September 30, 2018	—		960		960
September 30, 2019	—		614		614

The Company’s proved undeveloped (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 Company’s PUD reserves increased from 612 Bcfe at September 30, 2017 to 757 Bcfe at September 30, 2018. PUD reserves in the Marcellus Shale decreased from 456 Bcfe at September 30, 2017 to 394 Bcfe at September 30, 2018. PUD reserves in the Utica Shale increased from 154 Bcfe at September 30, 2017 to 357 Bcfe at September 30, 2018. The Company’s total PUD reserves were 30% of total proved reserves at September 30, 2018, up from 28% of total proved reserves at September 30, 2017.

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

The increase in PUD reserves in 2018 of 145 Bcfe is a result of 431 Bcfe in new PUD reserve additions (229 Bcfe from the Marcellus Shale, 197 Bcfe from the Utica Shale and 5 Bcfe from the West Coast region) and 60 Bcfe in upward revisions to remaining PUD reserves, partially offset by 284 Bcfe in PUD conversions to developed reserves (264 Bcfe from the Marcellus Shale, 18 Bcfe from the Utica Shale and 2 Bcfe from the West Coast region), 5 Bcfe in PUD reserves removed for one Marcellus PUD and sales of 57 Bcfe in PUD working interest reserves sold as part of a joint development agreement with IOG CRV - Marcellus, LLC.

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, 2018.

The Company invested $182 million during the year ended September 30, 2018 to convert 284 Bcfe of predominantly Marcellus and Utica Shale PUD reserves to developed reserves. This represents 46% of the net PUD reserves recorded at September 30, 2017 (or 51% of remaining net PUD reserves after 57 Bcfe in PUD working interest reserves were sold as part of the joint development agreement, as previously discussed). In fiscal 2018, the Company developed 53 (or 62%) of its well locations with net PUD reserves recorded at September 30, 2017. The vast majority of these wells were in the Appalachian region.

In 2020, the Company estimates that it will invest approximately $251 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 33% of its beginning year PUD reserves in fiscal 2015, 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 and 39% of its beginning year PUD reserves in fiscal 2019.

At September 30, 2019, the Company does not have a material concentration of 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
	2019		2018		2017
	(Thousands)
United States
Future Cash Inflows	$	8,738,182	$	7,822,855	$	6,144,317
Less:
Future Production Costs	2,989,518		2,606,411		2,378,262
Future Development Costs	797,640		559,707		411,578
Future Income Tax Expense at Applicable Statutory Rate	1,159,882		1,125,910		1,160,469
Future Net Cash Flows	3,791,142		3,530,827		2,194,008
Less:
10% Annual Discount for Estimated Timing of Cash Flows	2,054,823		1,810,522		1,080,962
Standardized Measure of Discounted Future Net Cash Flows	$	1,736,319	$	1,720,305	$	1,113,046



	Year Ended September 30
	2019			2018			2017
	(Thousands)
United States
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year	$	1,720,305		$	1,113,046		$	642,528
Sales, Net of Production Costs	(425,773		)	(381,775		)	(345,075		)
Net Changes in Prices, Net of Production Costs	(164,428		)	541,021			828,187
Extensions and Discoveries	202,683			212,494			170,500
Changes in Estimated Future Development Costs	(69,254		)	(43,771		)	8,816
Sales of Minerals in Place	—			(100,816		)	(9,849		)
Previously Estimated Development Costs Incurred	245,964			182,348			101,134
Net Change in Income Taxes at Applicable Statutory Rate	21,370			55,558			(393,353		)
Revisions of Previous Quantity Estimates	53,777			61,363			39,078
Accretion of Discount and Other	151,675			80,837			71,080
Standardized Measure of Discounted Future Net Cash Flows at End of Year	$	1,736,319		$	1,720,305		$	1,113,046