Supplementary Information for Oil and Gas Producing Activities (unaudited, except for Capitalized Costs Relating to Oil and Gas Producing Activities)

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

Capitalized Costs Relating to Oil and Gas Producing Activities



	At September 30
	2018		2017
	(Thousands)
Proved Properties(1)	$	5,114,753	$	4,832,301
Unproved Properties	62,234		80,932
	5,176,987		4,913,233
Less — Accumulated Depreciation, Depletion and Amortization	3,862,687		3,765,710
	$	1,314,300	$	1,147,523


(1)	Includes asset retirement costs of $44.3 million and $54.4 million at September 30, 2018 and 2017, 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 2023. It expects the majority of its development and exploration costs associated with unproved properties to be transferred into the amortization base by 2020. Following is a summary of costs excluded from amortization at September 30, 2018:



	Total as of September 30, 2018		Year Costs Incurred
	Total as of September 30, 2018		2018		2017		2016		Prior
	(Thousands)
Acquisition Costs	$	39,681	$	—	$	—	$	—	$	39,681
Development Costs	14,824		11,115		236		2,886		587
Exploration Costs	7,606		—		32		7,574		—
Capitalized Interest	123		20		—		103		—
	$	62,234	$	11,135	$	268	$	10,563	$	40,268

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities



	Year Ended September 30
	2018			2017			2016
	(Thousands)
United States
Property Acquisition Costs:
Proved	$	1,544		$	8,908		$	1,342
Unproved	4,286			262			2,165
Exploration Costs(1)	29,365			40,975			27,561
Development Costs(2)	332,496			200,639			219,386
Asset Retirement Costs	(10,107		)	(9,175		)	(49,653		)
	$	357,584		$	241,609		$	200,801


(1)	Amounts for 2018, 2017 and 2016 include capitalized interest of zero, $0.3 million and $0.3 million, respectively.


(2)	Amounts for 2018, 2017 and 2016 include capitalized interest of $0.3 million, $0.2 million and $0.2 million, respectively.

For the years ended September 30, 2018, 2017 and 2016, the Company spent $182.3 million, $101.1 million and $92.8 million, respectively, developing proved undeveloped reserves.

Results of Operations for Producing Activities



	Year Ended September 30
	2018		2017		2016
United States	(Thousands, except per Mcfe amounts)
Operating Revenues:
Natural Gas (includes transfers to operations of $2,134, $2,357 and $1,765, respectively)(1)	$	390,642	$	399,975	$	282,619
Oil, Condensate and Other Liquids	168,254		126,517		103,533
Total Operating Revenues(2)	558,896		526,492		386,152
Production/Lifting Costs	162,721		165,991		153,914
Franchise/Ad Valorem Taxes	14,355		15,372		13,794
Purchased Emission Allowance Expense	1,883		1,391		700
Accretion Expense	4,266		4,896		6,663
Depreciation, Depletion and Amortization ($0.67, $0.63 and $0.85 per Mcfe of production, respectively)	119,946		108,471		136,579
Impairment of Oil and Gas Producing Properties	—		—		948,307
Income Tax Expense (Benefit)	72,723		86,657		(368,940		)
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)	$	183,002	$	143,714	$	(504,865	)


(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 G — Financial Instruments.

Reserve Quantity Information

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 2004 and with over 5 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, 2018 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, 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, 2015	2,092,782			49,346		2,142,128
Extensions and Discoveries	185,347		(1)	—		185,347
Revisions of Previous Estimates	(245,029	)		(3,132	)	(248,161	)
Production	(140,457	)	(2)	(3,090	)	(143,547	)
Sale of Minerals in Place	(261,192	)		—		(261,192	)
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
Proved Developed Reserves:
September 30, 2015	1,267,498			49,346		1,316,844
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
Proved Undeveloped Reserves:
September 30, 2015	825,284			—		825,284
September 30, 2016	541,959			—		541,959
September 30, 2017	610,018			—		610,018
September 30, 2018	750,810			—		750,810


(1)	Extensions and discoveries include 179 Bcf (during 2016), 181 Bcf (during 2017) and 274 Bcf (during 2018), of Marcellus Shale gas in the Appalachian region. Extensions and discoveries include 6 Bcf (during 2016), 205 Bcf (during 2017) and 248 Bcf (during 2018), of Utica Shale gas in the Appalachian region.


(2)	Production includes 135,598 MMcf (during 2016), 145,452 MMcf (during 2017) and 150,196 MMcf (during 2018), from Marcellus Shale fields (which exceed 15% of total reserves). Production includes 9,409 MMcf (during 2018), from Utica Shale fields (which exceed 15% of total reserves).



	Oil Mbbl
	U.S.
	Appalachian Region		West Coast Region		Total Company
Proved Developed and Undeveloped Reserves:
September 30, 2015	220		33,502		33,722
Extensions and Discoveries	—		530		530
Revisions of Previous Estimates	(46	)	(2,201	)	(2,247	)
Production	(28	)	(2,895	)	(2,923	)
Sales of Minerals in Place	(73	)	—		(73	)
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
Proved Developed Reserves:
September 30, 2015	220		33,150		33,370
September 30, 2016	73		28,698		28,771
September 30, 2017	28		29,771		29,799
September 30, 2018	14		26,689		26,703
Proved Undeveloped Reserves:
September 30, 2015	—		352		352
September 30, 2016	—		238		238
September 30, 2017	—		408		408
September 30, 2018	—		960		960

The Company’s proved undeveloped (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 Company’s PUD reserves increased from 543 Bcfe at September 30, 2016 to 612 Bcfe at September 30, 2017. PUD reserves in the Marcellus Shale decreased from 542 Bcfe at September 30, 2016 to 456 Bcfe at September 30, 2017. The Company’s total PUD reserves were 28% of total proved reserves at September 30, 2017, down from 29% of total proved reserves at September 30, 2016.

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 the joint development agreement, previously discussed.

The increase in PUD reserves in 2017 of 69 Bcfe was a result of 269 Bcfe in new PUD reserve additions (113 Bcfe from the Marcellus Shale, 154 Bcfe from the Utica Shale and 2 Bcfe from the West Coast region) and 13 Bcfe in upward revisions to remaining PUD reserves, partially offset by 159 Bcfe in PUD conversions to developed reserves (158 Bcfe from the Marcellus Shale and 1 Bcfe from the West Coast region) and 54 Bcfe in PUD reserves removed. In the Eastern Development Area, Marcellus Shale PUD reserves of 36 Bcfe were removed due to development timing no longer scheduled to meet the five year requirement for proved reserves. Seneca successfully leased an adjacent tract to these wells in 2017 and intends to develop the wells now with longer laterals drilled into this adjacent tract. These development plans are not expected to commence within the five year time horizon from original booking. Marcellus Shale PUD reserves of 18 Bcfe were removed as part of Seneca’s transition toward a Utica focused development program in the Western Development Area, where certain Marcellus well locations were replaced with Utica well locations in the Company's development plan.

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 booked 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.

The Company invested $101 million during the year ended September 30, 2017 to convert 147 Bcfe of Marcellus Shale PUD reserves to developed reserves. This represents 27% of the net PUD reserves booked at September 30, 2016. In fiscal 2017, the Company developed 37 (or 41%) of its well locations with net PUD reserves recorded at September 30, 2016. The vast majority of these wells were in the Appalachian region.

In 2019, the Company estimates that it will invest approximately $210 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 51% of its beginning year PUD reserves in fiscal 2014, 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 and 51% of its beginning year PUD reserves in fiscal 2018.

At September 30, 2018, 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.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas 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 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
	2018		2017		2016
	(Thousands)
United States
Future Cash Inflows	$	7,822,855	$	6,144,317	$	3,768,463
Less:
Future Production Costs	2,606,411		2,378,262		1,994,916
Future Development Costs	559,707		411,578		375,152
Future Income Tax Expense at Applicable Statutory Rate	1,125,910		1,160,469		303,397
Future Net Cash Flows	3,530,827		2,194,008		1,094,998
Less:
10% Annual Discount for Estimated Timing of Cash Flows	1,810,522		1,080,962		452,470
Standardized Measure of Discounted Future Net Cash Flows	$	1,720,305	$	1,113,046	$	642,528

The principal sources of change in the standardized measure of discounted future net cash flows were as follows:



	Year Ended September 30
	2018			2017			2016
	(Thousands)
United States
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year	$	1,113,046		$	642,528		$	1,323,034
Sales, Net of Production Costs	(381,775		)	(345,075		)	(218,444		)
Net Changes in Prices, Net of Production Costs	541,021			828,187			(1,066,593		)
Extensions and Discoveries	212,494			170,500			47,742
Changes in Estimated Future Development Costs	(43,771		)	8,816			143,752
Sales of Minerals in Place	(100,816		)	(9,849		)	(95,849		)
Previously Estimated Development Costs Incurred	182,348			101,134			92,840
Net Change in Income Taxes at Applicable Statutory Rate	55,558			(393,353		)	387,739
Revisions of Previous Quantity Estimates	61,363			39,078			6,202
Accretion of Discount and Other	80,837			71,080			22,105
Standardized Measure of Discounted Future Net Cash Flows at End of Year	$	1,720,305		$	1,113,046		$	642,528