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
	2015		2014
	(Thousands)
Proved Properties(1)	$	4,473,721	$	3,941,143
Unproved Properties	176,327		141,719
	4,650,048		4,082,862
Less — Accumulated Depreciation, Depletion and Amortization	2,572,348		1,211,610
	$	2,077,700	$	2,871,252


(1)	Includes asset retirement costs of $113.3 million and $75.7 million at September 30, 2015 and 2014, 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 2020. It expects the majority of its development and exploration costs associated with unproved properties to be transferred into the amortization base by 2016. Following is a summary of costs excluded from amortization at September 30, 2015:



	Total as of September 30, 2015		Year Costs Incurred
	Total as of September 30, 2015		2015		2014		2013		Prior
	(Thousands)
Acquisition Costs	$	61,253	$	2,777	$	7,057	$	905	$	50,514
Development Costs	86,641		74,444		9,343		665		2,189
Exploration Costs	27,815		10,210		17,605		—		—
Capitalized Interest	618		303		315		—		—
	$	176,327	$	87,734	$	34,320	$	1,570	$	52,703

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



	Year Ended September 30
	2015		2014			2013
	(Thousands)
United States
Property Acquisition Costs:
Proved	$	1,767	$	18,213		$	7,575
Unproved	19,998		7,884			9,274
Exploration Costs(1)	53,222		71,850			49,483
Development Costs(2)	454,605		490,164			460,554
Asset Retirement Costs	37,595		(4,946		)	37,546
	$	567,187	$	583,165		$	564,432


(1)	Amounts for 2015, 2014 and 2013 include capitalized interest of $0.4 million, $0.7 million and $0.4 million, respectively.


(2)	Amounts for 2015, 2014 and 2013 include capitalized interest of $0.5 million, $0.7 million and $0.7 million, respectively.

For the years ended September 30, 2015, 2014 and 2013, the Company spent $161.8 million, $179.9 million and $148.5 million, respectively, developing proved undeveloped reserves.

Results of Operations for Producing Activities



	Year Ended September 30
	2015			2014		2013
	(Thousands, except per Mcfe amounts)
United States
Operating Revenues:
Natural Gas (includes revenues from sales to affiliates of $1 for all years presented and transfers to operations of $1,946, $2,145 and $612, respectively)	$	350,673		$	515,080	$	371,311
Oil, Condensate and Other Liquids	156,048			298,179		291,762
Total Operating Revenues(1)	506,721			813,259		663,073
Production/Lifting Costs	167,800			165,534		119,243
Franchise/Ad Valorem Taxes	20,167			20,765		17,200
Purchased Emission Allowance Expense	3,089			—		—
Accretion Expense	6,186			6,192		3,929
Depreciation, Depletion and Amortization ($1.49, $1.82 and $1.98 per Mcfe of production)	234,480			291,651		238,467
Impairment of Oil and Gas Producing Properties	1,126,257			—		—
Income Tax Expense	(444,393		)	140,484		120,431
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)	$	(606,865	)	$	188,633	$	163,803


(1)	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 25 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 for the past twelve years. 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 that determines 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 1998 with over 13 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, 2015 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, state data-sites and 2D and 3D seismic data. This data was 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, 2012	925,411			63,023		988,434
Extensions and Discoveries	360,922		(1)	702		361,624
Revisions of Previous Estimates	53,038			112		53,150
Production	(100,633	)	(2)	(3,060	)	(103,693	)
September 30, 2013	1,238,738			60,777		1,299,515
Extensions and Discoveries	446,821		(1)	—		446,821
Revisions of Previous Estimates	43,690			1,358		45,048
Production	(139,097	)	(2)	(3,210	)	(142,307	)
Purchases of Minerals in Place	33,986			—		33,986
Sale of Minerals in Place	(76	)		(103	)	(179	)
September 30, 2014	1,624,062			58,822		1,682,884
Extensions and Discoveries	633,360		(1)	—		633,360
Revisions of Previous Estimates	(28,124	)		(6,317	)	(34,441	)
Production	(136,404	)	(2)	(3,159	)	(139,563	)
Sale of Minerals in Place	(112	)		—		(112	)
September 30, 2015	2,092,782			49,346		2,142,128
Proved Developed Reserves:
September 30, 2012	544,560			59,923		604,483
September 30, 2013	807,055			59,862		866,917
September 30, 2014	1,119,901			57,907		1,177,808
September 30, 2015	1,267,498			49,346		1,316,844
Proved Undeveloped Reserves:
September 30, 2012	380,851			3,100		383,951
September 30, 2013	431,683			915		432,598
September 30, 2014	504,161			915		505,076
September 30, 2015	825,284			—		825,284


(1)	Extensions and discoveries include 355 Bcf (during 2013), 442 Bcf (during 2014) and 598 Bcf (during 2015), of Marcellus Shale gas in the Appalachian Region.


(2)	Production includes 93,999 MMcf (during 2013), 131,590 MMcf (during 2014) and 130,291 MMcf (during 2015), from Marcellus 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, 2012	306		42,556		42,862
Extensions and Discoveries	—		2,443		2,443
Revisions of Previous Estimates	5		(881	)	(876	)
Production	(28	)	(2,803	)	(2,831	)
September 30, 2013	283		41,315		41,598
Extensions and Discoveries	18		1,521		1,539
Revisions of Previous Estimates	(17	)	(1,677	)	(1,694	)
Production	(31	)	(3,005	)	(3,036	)
Purchases of Minerals in Place	—		83		83
Sales of Minerals in Place	—		(13	)	(13	)
September 30, 2014	253		38,224		38,477
Extensions and Discoveries	—		533		533
Revisions of Previous Estimates	(3	)	(2,251	)	(2,254	)
Production	(30	)	(3,004	)	(3,034	)
September 30, 2015	220		33,502		33,722
Proved Developed Reserves:
September 30, 2012	306		38,138		38,444
September 30, 2013	283		38,082		38,365
September 30, 2014	253		37,002		37,255
September 30, 2015	220		33,150		33,370
Proved Undeveloped Reserves:
September 30, 2012	—		4,418		4,418
September 30, 2013	—		3,233		3,233
September 30, 2014	—		1,222		1,222
September 30, 2015	—		352		352

The Company’s proved undeveloped (PUD) reserves increased from 512 Bcfe at September 30, 2014 to 827 Bcfe at September 30, 2015. PUD reserves in the Marcellus Shale increased from 504 Bcfe at September 30, 2014 to 825 Bcfe at September 30, 2015. The Company’s total PUD reserves were 35% of total proved reserves at September 30, 2015, up from 27% of total proved reserves at September 30, 2014.

The Company’s PUD reserves increased from 452 Bcfe at September 30, 2013 to 512 Bcfe at September 30, 2014. PUD reserves in the Marcellus Shale increased from 432 Bcfe at September 30, 2013 to 504 Bcfe at September 30, 2014. The Company’s total PUD reserves were 27% of total proved reserves at September 30, 2014, down from 29% of total proved reserves at September 30, 2013.

The increase in PUD reserves in 2015 of 315 Bcfe is a result of 496 Bcfe in new PUD reserve additions (494 Bcfe from the Marcellus Shale), 26 Bcfe in upward revisions to remaining PUD reserves, offset by 168 Bcfe in PUD conversions to developed reserves and 39 Bcfe in PUD reserves removed. The PUD reserves removed were primarily in the Marcellus Shale (37 Bcfe) in Tioga County, where the Company has no near term plans to develop these reserves as it is employing capital elsewhere. An additional 2 Bcfe (279 Mbbl) of PUD reserves were removed at the Midway Sunset field in the Tulare reservoir as the Company has no near term plans to develop these reserves as it is employing capital elsewhere.

The increase in PUD reserves in 2014 of 60 Bcfe is a result of 290 Bcfe in new PUD reserve additions (288 Bcfe from the Marcellus Shale), 20 Bcfe in PUD reserves acquired, 12 Bcfe in upward revisions to remaining PUD reserves, offset by 229 Bcfe in PUD conversions to developed reserves and 33 Bcfe in PUD reserves removed. The PUD reserves removed were primarily in the Marcellus Shale (24 Bcfe) in Seneca’s non-operated joint venture in Clearfield County where the operator had previously drilled and cased the horizontal wells to total depth and does not appear now to have firm plans for their completion. An additional 9 Bcfe (1,501 Mbbl) of PUD reserves were removed at the Midway Sunset field in the Tulare reservoir as the Company has no near term plans to develop these reserves as it is employing capital elsewhere.

The Company invested $162 million during the year ended September 30, 2015 to convert 168 Bcfe (184 Bcfe including revisions) of PUD reserves to developed reserves. This represents 33% of the PUD reserves booked at September 30, 2014. The Company invested $180 million during the year ended September 30, 2014 to convert 229 Bcfe (248 Bcfe including revisions) of September 30, 2013 PUD reserves to proved developed reserves. This represented 51% of the PUD reserves booked at September 30, 2013. In 2016, the Company estimates that it will invest approximately $166 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 47% of its beginning year PUD reserves in fiscal 2011, 33% of its beginning year PUD reserves in fiscal 2012, 39% of its beginning year PUD reserves in fiscal 2013, 51% of its beginning year PUD reserves in fiscal 2014 and 33% of its beginning year PUD reserves in fiscal 2015.

At September 30, 2015, 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
	2015		2014		2013
	(Thousands)
United States
Future Cash Inflows	$	6,916,775	$	10,001,545	$	8,943,942
Less:
Future Production Costs	2,854,142		2,795,657		2,334,393
Future Development Costs	761,922		790,033		749,876
Future Income Tax Expense at Applicable Statutory Rate	1,117,433		2,434,370		2,113,101
Future Net Cash Flows	2,183,278		3,981,485		3,746,572
Less:
10% Annual Discount for Estimated Timing of Cash Flows	860,244		1,914,607		1,780,206
Standardized Measure of Discounted Future Net Cash Flows	$	1,323,034	$	2,066,878	$	1,966,366

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



	Year Ended September 30
	2015			2014			2013
	(Thousands)
United States
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year	$	2,066,878		$	1,966,366		$	1,469,791
Sales, Net of Production Costs	(318,753		)	(626,960		)	(526,630		)
Net Changes in Prices, Net of Production Costs	(1,752,843		)	(38,723		)	339,655
Extensions and Discoveries	266,159			381,008			390,255
Changes in Estimated Future Development Costs	164,510			68,731			6,117
Purchases of Minerals in Place	—			34,705			—
Sales of Minerals in Place	(1		)	(691		)	—
Previously Estimated Development Costs Incurred	161,833			179,502			148,535
Net Change in Income Taxes at Applicable Statutory Rate	545,442			(231,807		)	(130,574		)
Revisions of Previous Quantity Estimates	(16,573		)	55,184			34,864
Accretion of Discount and Other	206,382			279,563			234,353
Standardized Measure of Discounted Future Net Cash Flows at End of Year	$	1,323,034		$	2,066,878		$	1,966,366