NATIONAL FUEL GAS CO, 10-K filed on 11/17/2017
Annual Report
Document And Entity Information (USD $)
12 Months Ended
Sep. 30, 2017
Oct. 31, 2017
Mar. 31, 2017
Document And Entity Information [Abstract]
 
 
 
Document Type
10-K 
 
 
Amendment Flag
false 
 
 
Document Period End Date
Sep. 30, 2017 
 
 
Document Fiscal Year Focus
2017 
 
 
Document Fiscal Period Focus
FY 
 
 
Entity Registrant Name
NATIONAL FUEL GAS CO 
 
 
Entity Central Index Key
0000070145 
 
 
Current Fiscal Year End Date
--09-30 
 
 
Entity Filer Category
Large Accelerated Filer 
 
 
Entity Common Stock, Shares Outstanding
 
85,582,201 
 
Entity Public Float
 
 
$ 4,970,818,000 
Entity Current Reporting Status
Yes 
 
 
Entity Well-known Seasoned Issuer
Yes 
 
 
Entity Voluntary Filers
No 
 
 
Consolidated Statements Of Income And Earnings Reinvested In The Business (USD $)
In Thousands, except Share data, unless otherwise specified
12 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
INCOME
 
 
 
Operating Revenues
$ 1,579,881 
$ 1,452,416 
$ 1,760,913 
Operating Expenses:
 
 
 
Purchased Gas
275,254 
147,982 
349,984 
Property, Franchise and Other Taxes
84,995 
81,714 
89,564 
Depreciation, Depletion and Amortization
224,195 
249,417 
336,158 
Impairment of Oil and Gas Producing Properties
948,307 
1,126,257 
Total Operating Expenses
1,027,036 
1,868,934 
2,371,966 
Operating Income (Loss)
552,845 
(416,518)
(611,053)
Other Income (Expense):
 
 
 
Other Income
7,043 
9,820 
8,039 
Interest Income
4,113 
4,235 
3,922 
Interest Expense on Long-Term Debt
(116,471)
(117,347)
(95,916)
Other Interest Expense
(3,366)
(3,697)
(3,555)
Income (Loss) Before Income Taxes
444,164 
(523,507)
(698,563)
Income Tax Expense (Benefit)
160,682 
(232,549)
(319,136)
Net Income (Loss) Available for Common Stock
283,482 
(290,958)
(379,427)
EARNINGS REINVESTED IN THE BUSINESS
 
 
 
Balance at Beginning of Year
676,361 
1,103,200 
1,614,361 
Beginning Retained Earnings Unappropriated And Current Period Net Income Loss
959,843 
812,242 
1,234,934 
Dividends on Common Stock
(140,090)
(135,881)
(131,734)
Cumulative Effect of Adoption of Authoritative Guidance for Stock-Based Compensation
31,916 
Balance at End of Year
851,669 
676,361 
1,103,200 
Earnings Per Common Share, Basic:
 
 
 
Net Income (Loss) Available for Common Stock (in usd per share)
$ 3.32 
$ (3.43)
$ (4.50)
Earnings Per Common Share, Diluted:
 
 
 
Net Income (Loss) Available for Common Stock (in usd per share)
$ 3.30 
$ (3.43)
$ (4.50)
Weighted Average Number of Shares Outstanding:
 
 
 
Used in Basic Calculation
85,364,929 
84,847,993 
84,387,755 
Used in Diluted Calculation
86,021,386 
84,847,993 
84,387,755 
Utility and Energy Marketing [Member]
 
 
 
INCOME
 
 
 
Operating Revenues
755,485 
624,602 
860,618 
Operating Expenses:
 
 
 
Operation and Maintenance
199,293 
192,512 
203,249 
Exploration and Production and Other [Member]
 
 
 
INCOME
 
 
 
Operating Revenues
617,666 
611,766 
696,709 
Operating Expenses:
 
 
 
Operation and Maintenance
145,099 
160,201 
184,024 
Pipeline and Storage and Gathering [Member]
 
 
 
INCOME
 
 
 
Operating Revenues
206,730 
216,048 
203,586 
Operating Expenses:
 
 
 
Operation and Maintenance
$ 98,200 
$ 88,801 
$ 82,730 
Consolidated Statements Of Comprehensive Income (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
Statement of Comprehensive Income [Abstract]
 
 
 
Net Income (Loss) Available for Common Stock
$ 283,482 
$ (290,958)
$ (379,427)
Other Comprehensive Income (Loss), Before Tax:
 
 
 
Increase (Decrease) in the Funded Status of the Pension and Other Post-Retirement Benefit Plans
15,661 
(21,378)
(31,538)
Reclassification Adjustment for Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans
13,433 
10,068 
9,217 
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period
4,008 
1,524 
(3,234)
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period
5,347 
60,493 
381,018 
Reclassification Adjustment for Realized (Gains) Losses on Securities Available for Sale in Net Income
(1,575)
(1,374)
(591)
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income
(81,605)
(220,919)
(184,953)
Other Comprehensive Income (Loss), Before Tax
(44,731)
(171,586)
169,919 
Income Tax Expense (Benefit) Related to the Increase (Decrease) in the Funded Status of the Pension and Other Post-Retirement Benefit Plans
6,175 
(8,351)
(11,922)
Reclassification Adjustment for Income Tax Benefit Related to the Amortization of the Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans
4,929 
3,723 
3,375 
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period
1,505 
592 
(1,195)
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period
2,009 
18,648 
160,872 
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Securities Available for Sale in Net Income
(580)
(527)
(217)
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income
(34,286)
(86,659)
(78,345)
Income Taxes - Net
(20,248)
(72,574)
72,568 
Other Comprehensive Income (Loss)
(24,483)
(99,012)
97,351 
Comprehensive Income (Loss)
$ 258,999 
$ (389,970)
$ (282,076)
Consolidated Balance Sheets (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2017
Sep. 30, 2016
ASSETS
 
 
Property, Plant and Equipment
$ 9,945,560 
$ 9,539,581 
Less - Accumulated Depreciation, Depletion and Amortization
5,271,486 
5,085,099 
Property, Plant and Equipment, Net, Total
4,674,074 
4,454,482 
Cash and Temporary Cash Investments
555,530 
129,972 
Current Assets
 
 
Hedging Collateral Deposits
1,741 1
1,484 1
Receivables - Net of Allowance for Uncollectible Accounts of $22,526 and $21,109, Respectively
112,383 
133,201 
Unbilled Revenue
22,883 
18,382 
Gas Stored Underground
35,689 
34,332 
Materials and Supplies - at average cost
33,926 
33,866 
Unrecovered Purchased Gas Costs
4,623 
2,440 
Other Current Assets
51,505 
59,354 
Total Current Assets
818,280 
413,031 
Other Assets
 
 
Recoverable Future Taxes
181,363 
177,261 
Unamortized Debt Expense
1,159 
1,688 
Other Regulatory Assets
174,433 
320,750 
Deferred Charges
30,047 
20,978 
Other Investments
125,265 
110,664 
Goodwill
5,476 
5,476 
Prepaid Post-Retirement Benefit Costs
56,370 
17,649 
Fair Value of Derivative Financial Instruments
36,111 
113,804 
Other
742 
604 
Total Other Assets
610,966 
768,874 
Total Assets
6,103,320 
5,636,387 
Capitalization:
 
 
Common Stock, $1 Par Value Authorized - 200,000,000 Shares; Issued and Outstanding - 85,543,125 Shares and 85,118,886 Shares, Respectively
85,543 
85,119 
Paid In Capital
796,646 
771,164 
Earnings Reinvested in the Business
851,669 
676,361 
Accumulated Other Comprehensive Loss
(30,123)
(5,640)
Total Comprehensive Shareholders' Equity
1,703,735 
1,527,004 
Long-term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs
2,083,681 
2,086,252 
Total Capitalization
3,787,416 
3,613,256 
Current and Accrued Liabilities
 
 
Notes Payable to Banks and Commercial Paper
Current Portion of Long-Term Debt
300,000 2
2
Accounts Payable
126,443 
108,056 
Amounts Payable to Customers
19,537 
Dividends Payable
35,500 
34,473 
Interest Payable on Long-Term Debt
35,031 
34,900 
Customer Advances
15,701 
14,762 
Customer Security Deposits
20,372 
16,019 
Other Accruals and Current Liabilities
111,889 
74,430 
Fair Value of Derivative Financial Instruments
1,103 
1,560 
Total Current and Accrued Liabilities
646,039 
303,737 
Deferred Credits
 
 
Deferred Income Taxes
891,287 
823,795 
Taxes Refundable to Customers
95,739 
93,318 
Cost of Removal Regulatory Liability
204,630 
193,424 
Other Regulatory Liabilities
113,716 
99,789 
Pension and Other Post-Retirement Liabilities
149,079 
277,113 
Asset Retirement Obligations
106,395 
112,330 
Other Deferred Credits
109,019 
119,625 
Total Deferred Credits
1,669,865 
1,719,394 
Commitments and Contingencies (Note I)
Total Capitalization and Liabilities
$ 6,103,320 
$ 5,636,387 
Consolidated Balance Sheets (Parenthetical) (USD $)
In Thousands, except Share data, unless otherwise specified
Sep. 30, 2017
Sep. 30, 2016
Statement of Financial Position [Abstract]
 
 
Receivables, Allowance for Uncollectible Accounts
$ 22,526 
$ 21,109 
Common Stock, Par Value
$ 1 
$ 1 
Common Stock, Shares Authorized
200,000,000 
200,000,000 
Common Stock, Shares Issued
85,543,125 
85,118,886 
Common Stock, Shares Outstanding
85,543,125 
85,118,886 
Consolidated Statements Of Cash Flows (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
Operating Activities
 
 
 
Net Income (Loss) Available for Common Stock
$ 283,482 
$ (290,958)
$ (379,427)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:
 
 
 
Impairment of Oil and Gas Producing Properties
948,307 
1,126,257 
Depreciation, Depletion and Amortization
224,195 
249,417 
336,158 
Deferred Income Taxes
117,975 
(246,794)
(357,587)
Excess Tax Benefits Associated with Stock-Based Compensation Awards
(1,868)
(9,064)
Stock-Based Compensation
12,262 
5,755 
3,208 
Other
16,476 
12,620 
9,823 
Change in:
 
 
 
Hedging Collateral Deposits
(257)
9,640 
(8,390)
Receivables and Unbilled Revenue
(3,380)
(6,408)
51,638 
Gas Stored Underground and Materials and Supplies
(1,417)
(3,532)
3,438 
Unrecovered Purchased Gas Costs
(2,183)
(2,440)
Other Current Assets
7,849 
3,179 
3,150 
Accounts Payable
17,192 
(40,664)
34,687 
Amounts Payable to Customers
(19,537)
(37,241)
23,033 
Customer Advances
939 
(1,474)
(2,769)
Customer Security Deposits
4,353 
(471)
729 
Other Accruals and Current Liabilities
27,004 
3,453 
(7,173)
Other Assets
(2,885)
1,941 
2,696 
Other Liabilities
2,183 
(13,483)
23,173 
Net Cash Provided by Operating Activities
684,251 
588,979 
853,580 
Investing Activities
 
 
 
Capital Expenditures
(450,335)
(581,576)
(1,018,179)
Net Proceeds from Sale of Oil and Gas Producing Properties
26,554 
137,316 
Other
1,216 
(9,236)
(6,611)
Net Cash Used in Investing Activities
(422,565)
(453,496)
(1,024,790)
Financing Activities
 
 
 
Change in Notes Payable to Banks and Commercial Paper
(85,600)
Excess Tax Benefits Associated with Stock-Based Compensation Awards
1,868 
9,064 
Net Proceeds from Issuance of Long-Term Debt
295,151 
444,635 
Net Proceeds from Issuance of Common Stock
7,784 
13,849 
10,540 
Dividends Paid on Common Stock
(139,063)
(134,824)
(130,719)
Net Cash Provided by (Used in) Financing Activities
163,872 
(119,107)
247,920 
Net Increase in Cash and Temporary Cash Investments
425,558 
16,376 
76,710 
Cash and Temporary Cash Investments At Beginning of Year
129,972 
113,596 
36,886 
Cash and Temporary Cash Investments At End of Year
555,530 
129,972 
113,596 
Supplemental Disclosure of Cash Flow Information
 
 
 
Cash Paid for Interest
116,894 
119,563 
90,747 
Cash Paid for Income Taxes
34,826 
34,240 
18,657 
Supplemental Disclosure of Cash Flow Information, Non-Cash Investing Activities
 
 
 
Non-Cash Capital Expenditures
72,216 
60,434 
118,959 
Receivable from Sale of Oil and Gas Producing Properties
$ 0 
$ 19,543 
$ 0 
Summary Of Significant Accounting Policies
Summary Of Significant Accounting Policies
Summary of Significant Accounting Policies
Principles of Consolidation
The Company consolidates all entities in which it has a controlling financial interest. All significant intercompany balances and transactions are eliminated. The Company uses proportionate consolidation when accounting for drilling arrangements related to oil and gas producing properties accounted for under the full cost method of accounting.
The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Reclassification
Certain prior year amounts have been reclassified to conform with current year presentation.
Regulation
The Company is subject to regulation by certain state and federal authorities. The Company has accounting policies which conform to GAAP, as applied to regulated enterprises, and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. Reference is made to Note C — Regulatory Matters for further discussion.
Revenue Recognition
The Company’s Exploration and Production segment records revenue based on entitlement, which means that revenue is recorded based on the actual amount of gas or oil that is delivered to a pipeline and the Company’s ownership interest in the producing well. If a production imbalance occurs between what was supposed to be delivered to a pipeline and what was actually produced and delivered, the Company accrues the difference as an imbalance.
The Company’s Pipeline and Storage segment records revenue for natural gas transportation and storage services. Revenue from reservation charges on firm contracted capacity is recognized through equal monthly charges over the contract period regardless of the amount of gas that is transported or stored. Commodity charges on firm contracted capacity and interruptible contracts are recognized as revenue when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage field. The point of delivery into the pipeline or injection or withdrawal from storage is the point at which ownership and risk of loss transfers to the buyer of such transportation and storage services.
In the Company’s Gathering segment, revenue is recorded at the point at which gathered volumes are delivered into interstate pipelines.
The Company’s Utility segment records revenue for gas sales and transportation in the period that gas is delivered to customers. This includes the recording of receivables for gas delivered but not yet billed to customers based on the Company's estimate of the amount of gas delivered between the last meter reading date and the end of the accounting period. Such receivables are a component of Unbilled Revenue on the Consolidated Balance Sheets.
The Company’s Energy Marketing segment records revenue for gas sales in the period that gas is delivered to customers. This includes the recording of receivables for gas delivered but not yet billed to customers based on the Company's estimate of the amount of gas delivered between the last meter reading date and the end of the accounting period. Such receivables are a component of Unbilled Revenue on the Consolidated Balance Sheets.
Allowance for Uncollectible Accounts
The allowance for uncollectible accounts is the Company’s best estimate of the amount of probable credit losses in the existing accounts receivable. The allowance is determined based on historical experience, the age and other specific information about customer accounts. Account balances are charged off against the allowance twelve months after the account is final billed or when it is anticipated that the receivable will not be recovered.
Regulatory Mechanisms
The Company’s rate schedules in the Utility segment contain clauses that permit adjustment of revenues to reflect price changes from the cost of purchased gas included in base rates. Differences between amounts currently recoverable and actual adjustment clause revenues, as well as other price changes and pipeline and storage company refunds not yet includable in adjustment clause rates, are deferred and accounted for as either unrecovered purchased gas costs or amounts payable to customers. Such amounts are generally recovered from (or passed back to) customers during the following fiscal year.
Estimated refund liabilities to ratepayers represent management’s current estimate of such refunds. Reference is made to Note C — Regulatory Matters for further discussion.
The impact of weather on revenues in the Utility segment’s New York rate jurisdiction is tempered by a WNC, which covers the eight-month period from October through May. The WNC is designed to adjust the rates of retail customers to reflect the impact of deviations from normal weather. Weather that is warmer than normal results in a surcharge being added to customers’ current bills, while weather that is colder than normal results in a refund being credited to customers’ current bills. Since the Utility segment’s Pennsylvania rate jurisdiction does not have a WNC, weather variations have a direct impact on the Pennsylvania rate jurisdiction’s revenues.
The impact of weather normalized usage per customer account in the Utility segment’s New York rate jurisdiction is tempered by a revenue decoupling mechanism. The effect of the revenue decoupling mechanism is to render the Company financially indifferent to throughput decreases resulting from conservation. Weather normalized usage per account that exceeds the average weather normalized usage per customer account results in a refund being credited to customers’ bills. Weather normalized usage per account that is below the average weather normalized usage per account results in a surcharge being added to customers’ bills. The surcharge or credit is calculated over a twelve-month period ending December 31st, and applied to customer bills annually, beginning March 1st.
In the Pipeline and Storage segment, the allowed rates that Supply Corporation and Empire bill their customers are based on a straight fixed-variable rate design, which allows recovery of all fixed costs, including return on equity and income taxes, through fixed monthly reservation charges. Because of this rate design, changes in throughput due to weather variations do not have a significant impact on the revenues of Supply Corporation or Empire.
Property, Plant and Equipment
In the Company’s Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. For further discussion of capitalized costs, refer to Note M — Supplementary Information for Oil and Gas Producing Activities.
Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The natural gas and oil prices used to calculate the full cost ceiling are based on 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. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. At September 30, 2017, the ceiling exceeded the book value of the oil and gas properties by $286.4 million. In adjusting estimated future net cash flows for hedging under the ceiling test at September 30, 2017, 2016, and 2015, estimated future net cash flows were increased by $30.5 million, $215.3 million and $194.5 million, respectively.
On December 1, 2015, Seneca and IOG - CRV Marcellus, LLC (IOG), an affiliate of IOG Capital, LP, and funds managed by affiliates of Fortress Investment Group, LLC, executed a joint development agreement that allows IOG to participate in the development of certain oil and gas interests owned by Seneca in Elk, McKean and Cameron Counties, Pennsylvania. On June 13, 2016, Seneca and IOG executed an extension of the joint development agreement. Under the terms of the extended agreement, Seneca and IOG will jointly participate in a program to develop up to 75 Marcellus wells, with Seneca serving as program operator. IOG will hold an 80% working interest in all of the joint development wells. In total, IOG is expected to fund approximately $325 million for its 80% working interest in the 75 joint development wells. Of this amount, IOG has funded $262.6 million as of September 30, 2017, which includes $163.9 million of cash ($137.3 million in fiscal 2016 and $26.6 million in fiscal 2017) that Seneca had received in recognition of IOG funding that is due to Seneca for costs previously incurred to develop a portion of the first 75 joint development wells. The cash proceeds were recorded by Seneca as a $163.9 million reduction of property, plant and equipment. The remainder funded joint development expenditures. As the fee-owner of the property’s mineral rights, Seneca retains a 7.5% royalty interest and the remaining 20% working interest (which results in a 26% net revenue interest) in 56 of the joint development wells. In the remaining 19 wells, Seneca retains a 20% working and net revenue interest. Seneca’s working interest under the agreement will increase to 85% after IOG achieves a 15% internal rate of return.
The principal assets of the Utility and Pipeline and Storage segments, consisting primarily of gas plant in service, are recorded at the historical cost when originally devoted to service.
Maintenance and repairs of property and replacements of minor items of property are charged directly to maintenance expense. The original cost of the regulated subsidiaries’ property, plant and equipment retired, and the cost of removal less salvage, are charged to accumulated depreciation.
 Depreciation, Depletion and Amortization
For oil and gas properties, depreciation, depletion and amortization is computed based on quantities produced in relation to proved reserves using the units of production method. The cost of unproved oil and gas properties is excluded from this computation. In the All Other category, for timber properties, depletion, determined on a property by property basis, is charged to operations based on the actual amount of timber cut in relation to the total amount of recoverable timber. For all other property, plant and equipment, depreciation and amortization is computed using the straight-line method in amounts sufficient to recover costs over the estimated service lives of property in service. The following is a summary of depreciable plant by segment:
 
As of September 30
 
2017
 
2016
 
(Thousands)
Exploration and Production
$
4,925,409

 
$
4,645,226

Pipeline and Storage
2,002,736

 
1,956,708

Gathering
484,768

 
454,343

Utility
2,045,074

 
1,998,605

Energy Marketing
3,564

 
3,528

All Other and Corporate
109,128

 
109,455

 
$
9,570,679

 
$
9,167,865


Average depreciation, depletion and amortization rates are as follows:
 
Year Ended September 30
 
2017
 
2016
 
2015
Exploration and Production, per Mcfe(1)
$
0.65

 
$
0.87

 
$
1.52

Pipeline and Storage
2.2
%
 
2.4
%
 
2.4
%
Gathering
3.4
%
 
4.0
%
 
4.0
%
Utility
2.8
%
 
2.7
%
 
2.6
%
Energy Marketing
7.9
%
 
7.9
%
 
6.1
%
All Other and Corporate
1.3
%
 
1.8
%
 
1.4
%
 
(1)
Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note M — Supplementary Information for Oil and Gas Producing Activities, depletion of oil and gas producing properties amounted to $0.63, $0.85 and $1.49 per Mcfe of production in 2017, 2016 and 2015, respectively.
Goodwill
The Company has recognized goodwill of $5.5 million as of September 30, 2017 and 2016 on its Consolidated Balance Sheets related to the Company’s acquisition of Empire in 2003. The Company accounts for goodwill in accordance with the current authoritative guidance, which requires the Company to test goodwill for impairment annually. At September 30, 2017, 2016 and 2015, the fair value of Empire was greater than its book value. As such, the goodwill was not considered impaired at those dates. Going back to the origination of the goodwill in 2003, the Company has never recorded an impairment of its goodwill balance.
Financial Instruments
Unrealized gains or losses from the Company’s investments in an equity mutual fund, a fixed income mutual fund and the stock of an insurance company (securities available for sale) are recorded as a component of accumulated other comprehensive income (loss). Reference is made to Note G — Financial Instruments for further discussion.
The Company uses a variety of derivative financial instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil and to manage a portion of the risk of currency fluctuations associated with transportation costs denominated in Canadian currency. These instruments include price swap agreements and futures contracts. The Company accounts for these instruments as either cash flow hedges or fair value hedges. In both cases, the fair value of the instrument is recognized on the Consolidated Balance Sheets as either an asset or a liability labeled Fair Value of Derivative Financial Instruments. Reference is made to Note F — Fair Value Measurements for further discussion concerning the fair value of derivative financial instruments.
For effective cash flow hedges, the offset to the asset or liability that is recorded is a gain or loss recorded in accumulated other comprehensive income (loss) on the Consolidated Balance Sheets. The gain or loss recorded in accumulated other comprehensive income (loss) remains there until the hedged transaction occurs, at which point the gains or losses are reclassified to operating revenues, purchased gas expense or operation and maintenance expense on the Consolidated Statements of Income. Reference is made to Note G - Financial Instruments for further discussion concerning cash flow hedges.
For fair value hedges, the offset to the asset or liability that is recorded is a gain or loss recorded to operating revenues or purchased gas expense on the Consolidated Statements of Income. However, in the case of fair value hedges, the Company also records an asset or liability on the Consolidated Balance Sheets representing the change in fair value of the asset or firm commitment that is being hedged (see Other Current Assets section in this footnote). The offset to this asset or liability is a gain or loss recorded to operating revenues or purchased gas expense on the Consolidated Statements of Income as well. If the fair value hedge is effective, the gain or loss from the derivative financial instrument is offset by the gain or loss that arises from the change in fair value of the asset or firm commitment that is being hedged. Reference is made to Note G - Financial Instruments for further discussion concerning fair value hedges.
Accumulated Other Comprehensive Income (Loss)
The components of Accumulated Other Comprehensive Income (Loss) and changes for the year ended September 30, 2017, net of related tax effect, are as follows (amounts in parentheses indicate debits) (in thousands):
 
Gains and Losses on Derivative Financial Instruments
 
Gains and Losses on Securities Available for Sale
 
Funded Status of the Pension and Other Post-Retirement Benefit Plans
 
Total
Year Ended September 30, 2017
 
 
 
 
 
 
 
Balance at October 1, 2016
$
64,782

 
$
6,054

 
$
(76,476
)
 
$
(5,640
)
Other Comprehensive Gains and Losses Before Reclassifications
3,338

 
2,503

 
9,486

 
15,327

Amounts Reclassified From Other Comprehensive Loss
(47,319
)
 
(995
)
 
8,504

 
(39,810
)
Balance at September 30, 2017
$
20,801

 
$
7,562

 
$
(58,486
)
 
$
(30,123
)
 
 
 
 
 
 
 
 
Year Ended September 30, 2016
 
 
 
 
 
 
 
Balance at October 1, 2015
$
157,197

 
$
5,969

 
$
(69,794
)
 
$
93,372

Other Comprehensive Gains and Losses Before Reclassifications
41,845

 
932

 
(13,027
)
 
29,750

Amounts Reclassified From Other Comprehensive Loss
(134,260
)
 
(847
)
 
6,345

 
(128,762
)
Balance at September 30, 2016
$
64,782

 
$
6,054

 
$
(76,476
)
 
$
(5,640
)

The amounts included in accumulated other comprehensive income (loss) related to the funded status of the Company’s pension and other post-retirement benefit plans consist of prior service costs and accumulated losses. The total amount for prior service cost was $1.2 million and $1.3 million at September 30, 2017 and 2016, respectively. The total amount for accumulated losses was $57.3 million and $75.2 million at September 30, 2017 and 2016, respectively.
Reclassifications Out of Accumulated Other Comprehensive Income (Loss) 
The details about the reclassification adjustments out of accumulated other comprehensive loss for the year ended September 30, 2017 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands):
Details About Accumulated Other
Comprehensive Income (Loss) Components
 
Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) for the
Year Ended
September 30,
 
Affected Line Item in the Statement Where Net Income (Loss) is Presented
 
 
2017
 
2016
 
 
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
 
 
 
 
 
 
Commodity Contracts
 

$83,983

 

$216,823

 
Operating Revenues
Commodity Contracts
 
(1,921
)
 
4,520

 
Purchased Gas
Foreign Currency Contracts
 
(457
)
 
(424
)
 
Operation and Maintenance Expense
Gains (Losses) on Securities Available for Sale
 
1,575

 
1,374

 
Other Income
Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans:
 
 
 
 
 
 
Prior Service Credit
 
(288
)
 
(333
)
 
(1)
Net Actuarial Loss
 
(13,145
)
 
(9,735
)
 
(1)
 
 
69,747

 
212,225

 
Total Before Income Tax
 
 
(29,937
)
 
(83,463
)
 
Income Tax Expense
 
 

$39,810

 

$128,762

 
Net of Tax
 
(1)
These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost. Refer to Note H — Retirement Plan and Other Post-Retirement Benefits for additional details.
Gas Stored Underground 
In the Utility segment, gas stored underground in the amount of $26.7 million is carried at lower of cost or net realizable value, on a LIFO method. Based upon the average price of spot market gas purchased in September 2017, including transportation costs, the current cost of replacing this inventory of gas stored underground exceeded the amount stated on a LIFO basis by approximately $17.1 million at September 30, 2017. All other gas stored underground, which is in the Energy Marketing segment, is carried at an average cost method, subject to lower of cost or net realizable value adjustments.
Unamortized Debt Expense
Costs associated with the reacquisition of debt related to rate-regulated subsidiaries are deferred and amortized over the remaining life of the issue or the life of the replacement debt in order to match regulatory treatment. At September 30, 2017, the remaining weighted average amortization period for such costs was approximately 2 years.
Income Taxes
The Company and its subsidiaries file a consolidated federal income tax return. State tax returns are filed on a combined or separate basis depending on the applicable laws in the jurisdictions where tax returns are filed. The investment tax credit, prior to its repeal in 1986, was deferred and is being amortized over the estimated useful lives of the related property, as required by regulatory authorities having jurisdiction.
The Company follows the asset and liability approach in accounting for income taxes, which requires the recognition of deferred income taxes for the expected future tax consequences of net operating losses, credits and temporary differences between the financial statement carrying amounts and the tax basis of assets and liabilities. A valuation allowance is provided on deferred tax assets if it is determined, within each taxing jurisdiction, that it is more likely than not that the asset will not be realized.
The Company reports a liability or a reduction of deferred tax assets for unrecognized tax benefits resulting from uncertain tax positions taken or expected to be taken in a tax return. When applicable, the Company recognizes interest relating to uncertain tax positions in Other Interest Expense and penalties in Other Income.
Consolidated Statement of Cash Flows
For purposes of the Consolidated Statement of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of generally three months or less to be cash equivalents.
Hedging Collateral Deposits
This is an account title for cash held in margin accounts funded by the Company to serve as collateral for hedging positions. In accordance with its accounting policy, the Company does not offset hedging collateral deposits paid or received against related derivative financial instrument liability or asset balances.
Other Current Assets
The components of the Company’s Other Current Assets are as follows: 
 
Year Ended September 30
 
2017
 
2016
 
(Thousands)
Prepayments
$
10,927

 
$
10,919

Prepaid Property and Other Taxes
13,974

 
13,138

Federal Income Taxes Receivable

 
11,758

State Income Taxes Receivable
9,689

 
3,961

Fair Values of Firm Commitments
1,031

 
3,962

Regulatory Assets
15,884

 
15,616

 
$
51,505

 
$
59,354


Other Accruals and Current Liabilities
The components of the Company’s Other Accruals and Current Liabilities are as follows:
 
Year Ended September 30
 
2017
 
2016
 
(Thousands)
Accrued Capital Expenditures
$
37,382

 
$
26,796

Regulatory Liabilities
34,059

 
14,725

Federal Income Taxes Payable
1,775

 

Other
38,673

 
32,909

 
$
111,889

 
$
74,430


Customer Advances
The Company’s Utility and Energy Marketing segments have balanced billing programs whereby customers pay their estimated annual usage in equal installments over a twelve-month period. Monthly payments under the balanced billing programs are typically higher than current month usage during the summer months. During the winter months, monthly payments under the balanced billing programs are typically lower than current month usage. At September 30, 2017 and 2016, customers in the balanced billing programs had advanced excess funds of $15.7 million and $14.8 million, respectively.
Customer Security Deposits
The Company, in its Utility, Pipeline and Storage, and Energy Marketing segments, often times requires security deposits from marketers, producers, pipeline companies, and commercial and industrial customers before providing services to such customers. At September 30, 2017 and 2016, the Company had received customer security deposits amounting to $20.4 million and $16.0 million, respectively.
Earnings Per Common Share
Basic earnings per common share is computed by dividing income or loss by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the potentially dilutive securities the Company has outstanding are stock options, SARs, restricted stock units and performance shares. For the year ended September 30, 2017, the diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method. Stock options, SARs, restricted stock units and performance shares that are antidilutive are excluded from the calculation of diluted earnings per common share. There were 157,649 shares excluded as being antidilutive for the year ended September 30, 2017. As the Company recognized net losses for the years ended September 30, 2016 and 2015, the aforementioned potentially dilutive securities, amounting to 431,408 shares and 709,063 shares, respectively, were not recognized in the diluted earnings per share calculation for 2016 and 2015.
Stock-Based Compensation
The Company has various stock option and stock award plans which provide or provided for the issuance of one or more of the following to key employees: incentive stock options, nonqualified stock options, SARs, restricted stock, restricted stock units, performance units or performance shares. The Company follows authoritative guidance which requires the measurement and recognition of compensation cost at fair value for all share-based payments. Stock options and SARs under all plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no stock option or SAR is exercisable less than one year or more than ten years after the date of each grant. The Company has chosen the Black-Scholes-Merton closed form model to calculate the compensation expense associated with stock options and SARs. For all Company stock awards, forfeitures are recognized as they occur.
Restricted stock is subject to restrictions on vesting and transferability. Restricted stock awards entitle the participants to full dividend and voting rights. The market value of restricted stock on the date of the award is recorded as compensation expense over the vesting period. Certificates for shares of restricted stock awarded under the Company’s stock option and stock award plans are held by the Company during the periods in which the restrictions on vesting are effective. Restrictions on restricted stock awards generally lapse ratably over a period of not more than ten years after the date of each grant. Restricted stock units also are subject to restrictions on vesting and transferability. Restricted stock units, both performance and non-performance based, represent the right to receive shares of common stock of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company) at the end of a specified time period. The performance based and non-performance based restricted stock units do not entitle the participants to dividend and voting rights. The accounting for performance based and non-performance based restricted stock units is the same as the accounting for restricted share awards, except that the fair value at the date of grant of the restricted stock units (represented by the market value of Company common stock on the date of the award) must be reduced by the present value of forgone dividends over the vesting term of the award. The fair value of restricted stock units on the date of award is recorded as compensation expense over the vesting period.
Performance shares are an award constituting units denominated in common stock of the Company, the number of which may be adjusted over a performance cycle based upon the extent to which performance goals have been satisfied. Earned performance shares may be distributed in the form of shares of common stock of the Company, an equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company. The performance shares do not entitle the participant to receive dividends during the vesting period. For performance shares based on a return on capital goal, the fair value at the date of grant of the performance shares is determined by multiplying the expected number of performance shares to be issued by the market value of Company common stock on the date of grant reduced by the present value of forgone dividends. For performance shares based on a total shareholder return goal, the Company uses the Monte Carlo simulation technique to estimate the fair value price at the date of grant.
Refer to Note E — Capitalization and Short-Term Borrowings under the heading “Stock Option and Stock Award Plans” for additional disclosures related to stock-based compensation awards for all plans.
New Authoritative Accounting and Financial Reporting Guidance
In May 2014, the FASB issued authoritative guidance regarding revenue recognition. The authoritative guidance provides a single, comprehensive revenue recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The original effective date of this authoritative guidance was as of the Company's first quarter of fiscal 2018. However, the FASB has delayed the effective date of the new revenue standard by one year, and the guidance will now be effective as of the Company's first quarter of fiscal 2019. Working towards this implementation date, the Company is currently evaluating the guidance and the various issues identified by industry based revenue recognition task forces. The Company does not believe that its revenue recognition policies will change materially, although the Company is still assessing the impact. The Company will need to enhance its financial statement disclosures to comply with the new authoritative guidance.
In May 2015, the FASB issued authoritative guidance related to the presentation of investments for which fair value was measured using net asset value per share (or its equivalent). In fiscal 2017, the Company adopted this authoritative guidance. As a result, the presentation of Retirement Plan Investments and Other Post-Retirement Benefit Assets has been adjusted (see tables in Note H — Retirement Plan and Other Post-Retirement Benefits).
In February 2016, the FASB issued authoritative guidance requiring organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by all leases, regardless of whether they are considered to be capital leases or operating leases. The FASB’s previous authoritative guidance required organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by capital leases while excluding operating leases from balance sheet recognition. The new authoritative guidance will be effective as of the Company’s first quarter of fiscal 2020, with early adoption permitted. The Company does not anticipate early adoption and is currently evaluating the provisions of the revised guidance.
In March 2016, the FASB issued authoritative guidance simplifying several aspects of the accounting for stock-based compensation. The Company adopted this guidance effective as of October 1, 2016, recognizing a cumulative effect adjustment that increased retained earnings by $31.9 million. The cumulative effect represents the tax benefit of previously unrecognized tax deductions in excess of stock compensation recorded for financial reporting purposes. On a prospective basis, the tax effect of all future differences between stock compensation recorded for financial reporting purposes and actual tax deductions for stock compensation will be recognized upon vesting or settlement as income tax expense or benefit in the income statement. From a statement of cash flows perspective, the tax benefits relating to differences between stock compensation recorded for financial reporting purposes and actual tax deductions for stock compensation are now included in cash provided by operating activities instead of cash provided by financing activities. The changes to the statement of cash flows have been applied prospectively and prior periods have not been adjusted.
In March 2017, the FASB issued authoritative guidance related to the presentation of net periodic pension cost and net periodic postretirement benefit cost. The new guidance requires segregation of the service cost component from the other components of net periodic pension cost and net periodic postretirement benefit cost for financial reporting purposes. The service cost component is to be presented on the income statement in the same line items as other compensation costs included within Operating Expenses and the other components of net periodic pension cost and net periodic postretirement benefit cost are to be presented on the income statement below the subtotal labeled Operating Income (Loss). Under this guidance, the service cost component shall be the only component eligible to be capitalized as part of the cost of inventory or property, plant and equipment. The new guidance will be effective as of the Company’s first quarter of fiscal 2019, with early adoption permitted. The Company does not anticipate early adoption and is currently evaluating the interaction of this authoritative guidance with the various regulatory provisions concerning pension and postretirement benefit costs in the Company’s Utility and Pipeline and Storage segments.
Asset Retirement Obligations
Asset Retirement Obligations
Asset Retirement Obligations
The Company accounts for asset retirement obligations in accordance with the authoritative guidance that requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. An asset retirement obligation is defined as a legal obligation associated with the retirement of a tangible long-lived asset in which the timing and/or method of settlement may or may not be conditional on a future event that may or may not be within the control of the Company. When the liability is initially recorded, the entity capitalizes the estimated cost of retiring the asset as part of the carrying amount of the related long-lived asset. Over time, the liability is adjusted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. The Company estimates the fair value of its asset retirement obligations based on the discounting of expected cash flows using various estimates, assumptions and judgments regarding certain factors such as the existence of a legal obligation for an asset retirement obligation; estimated amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. Asset retirement obligations incurred in the current period were Level 3 fair value measurements as the inputs used to measure the fair value are unobservable.
The Company has recorded an asset retirement obligation representing plugging and abandonment costs associated with the Exploration and Production segment’s crude oil and natural gas wells and has capitalized such costs in property, plant and equipment (i.e. the full cost pool).
In addition to the asset retirement obligation recorded in the Exploration and Production segment, the Company has recorded future asset retirement obligations associated with the plugging and abandonment of natural gas storage wells in the Pipeline and Storage segment and the removal of asbestos and asbestos-containing material in various facilities in the Utility and Pipeline and Storage segments. The Company has also recorded asset retirement obligations for certain costs connected with the retirement of the distribution mains and services components of the pipeline system in the Utility segment, the transmission mains and other components in the pipeline system in the Pipeline and Storage segment, and the gathering lines and other components in the Gathering segment. The retirement costs within the distribution, transmission and gathering systems are primarily for the capping and purging of pipe, which are generally abandoned in place when retired, as well as for the clean-up of PCB contamination associated with the removal of certain pipe.
On June 30, 2016, Seneca sold the majority of its Upper Devonian wells in Pennsylvania. While the proceeds from the sale were not significant, it did result in a $58.4 million reduction of its Asset Retirement Obligation at September 30, 2016, which is reflected in Liabilities Settled in the table below. The following is a reconciliation of the change in the Company’s asset retirement obligations:
 
Year Ended September 30
 
2017
 
2016
 
2015
 
(Thousands)
Balance at Beginning of Year
$
112,330

 
$
156,805

 
$
117,713

Liabilities Incurred
2,963

 
2,719

 
4,433

Revisions of Estimates
(10,578
)
 
16,721

 
33,717

Liabilities Settled
(4,967
)
 
(72,215
)
 
(6,825
)
Accretion Expense
6,647

 
8,300

 
7,767

Balance at End of Year
$
106,395

 
$
112,330

 
$
156,805

Regulatory Matters
Regulatory Matters
Regulatory Matters
Regulatory Assets and Liabilities
The Company has recorded the following regulatory assets and liabilities:
 
At September 30
 
2017
 
2016
 
(Thousands)
Regulatory Assets(1):
 
 
 
Pension Costs(2) (Note H)
$
125,175

 
$
203,755

Post-Retirement Benefit Costs(2) (Note H)
13,886

 
74,802

Recoverable Future Taxes (Note D)
181,363

 
177,261

Environmental Site Remediation Costs(2) (Note I)
19,665

 
23,392

Asset Retirement Obligations(2) (Note B)
12,764

 
12,490

Unamortized Debt Expense (Note A)
1,159

 
1,688

Other(3)
18,827

 
21,927

Total Regulatory Assets
372,839

 
515,315

Less: Amounts Included in Other Current Assets
(15,884
)
 
(15,616
)
Total Long-Term Regulatory Assets
$
356,955

 
$
499,699

 
 
At September 30
 
2017
 
2016
 
(Thousands)
Regulatory Liabilities:
 
 
 
Cost of Removal Regulatory Liability
$
204,630

 
$
193,424

Taxes Refundable to Customers (Note D)
95,739

 
93,318

Post-Retirement Benefit Costs (Note H)
102,891

 
67,204

Amounts Payable to Customers (See Regulatory Mechanisms in Note A)

 
19,537

Other(4)
44,884

 
47,310

Total Regulatory Liabilities
448,144

 
420,793

Less: Amounts included in Current and Accrued Liabilities
(34,059
)
 
(34,262
)
Total Long-Term Regulatory Liabilities
$
414,085

 
$
386,531

 
(1)
The Company recovers the cost of its regulatory assets but generally does not earn a return on them. There are a few exceptions to this rule. For example, the Company does earn a return on Unrecovered Purchased Gas Costs and, in the New York jurisdiction of its Utility segment, earns a return, within certain parameters, on the excess of cumulative funding to the pension plan over the cumulative amount collected in rates.
(2)
Included in Other Regulatory Assets on the Consolidated Balance Sheets.
(3)
$15,884 and $15,616 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2017 and 2016, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $2,943 and $6,311 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2017 and 2016, respectively.
(4)
$34,059 and $14,725 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2017 and 2016, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $10,825 and $32,585 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2017 and 2016, respectively.
If for any reason the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the Consolidated Balance Sheets and included in income of the period in which the discontinuance of regulatory accounting treatment occurs.
Cost of Removal Regulatory Liability
In the Company’s Utility and Pipeline and Storage segments, costs of removing assets (i.e. asset retirement costs) are collected from customers through depreciation expense. These amounts are not a legal retirement obligation as discussed in Note B — Asset Retirement Obligations. Rather, they are classified as a regulatory liability in recognition of the fact that the Company has collected dollars from the customer that will be used in the future to fund asset retirement costs.
NYPSC Rate Proceeding
On April 28, 2016, Distribution Corporation commenced a rate case by filing proposed tariff amendments and supporting testimony requesting approval to increase its annual revenues by approximately $41.7 million. Distribution Corporation explained in the filing that its request for rate relief was necessitated by a revenue requirement driven primarily by rate base growth, higher operating expense and higher depreciation expense, among other things. On January 23, 2017, the administrative law judge assigned to the proceeding issued a recommended decision (RD) in the case. The RD, as revised on January 26, 2017, recommended a rate increase designed to provide additional annual revenues of $8.5 million, an equity ratio, subject to update of 42.3% based on the Company’s equity ratio, and a cost of equity, subject to update of 8.6%. On April 20, 2017, the NYPSC issued an Order adopting some provisions of the RD and modifying or rejecting others. The Order provides for an annual rate increase of $5.9 million. The rate increase became effective May 1, 2017. The Order further provides for a return on equity of 8.7%, and established an equity ratio of 42.9%. The Order also directs the implementation of an earnings sharing mechanism to be in place beginning on April 1, 2018.
On July 28, 2017, Distribution Corporation filed an appeal with New York State Supreme Court, Albany County, seeking review of the Order. The appeal contends that portions of the Order should be invalidated because they fail to meet the applicable legal standard for agency decisions. On October 13, 2017, the NYPSC filed an answer which contained a request that the appeal be transferred to the Appellate Division. The Company cannot predict the outcome of the appeal at this time.
FERC Rate Proceedings
Supply Corporation currently has no active rate case on file. Supply Corporation's current rate settlement requires a rate case filing no later than December 31, 2019.
Empire currently has no active rate case on file. Empire’s current rate settlement requires a rate case filing no later than July 1, 2021.
Income Taxes
Income Taxes
Income Taxes
The components of federal and state income taxes included in the Consolidated Statements of Income are as follows:
 
Year Ended September 30
 
2017
 
2016
 
2015
 
(Thousands)
Current Income Taxes —
 
 
 
 
 
Federal
$
32,034

 
$
(6,658
)
 
$
25,064

State
10,673

 
20,903

 
13,387

Deferred Income Taxes —
 
 
 
 
 
Federal
103,046

 
(164,818
)
 
(244,336
)
State
14,929

 
(81,976
)
 
(113,251
)
 
160,682

 
(232,549
)
 
(319,136
)
Deferred Investment Tax Credit
(173
)
 
(348
)
 
(414
)
Total Income Taxes
$
160,509

 
$
(232,897
)
 
$
(319,550
)
Presented as Follows:
 
 
 
 
 
Other Income
$
(173
)
 
$
(348
)
 
$
(414
)
Income Tax Expense (Benefit)
160,682

 
(232,549
)
 
(319,136
)
Total Income Taxes
$
160,509

 
$
(232,897
)
 
$
(319,550
)

Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income (loss) before income taxes. The following is a reconciliation of this difference:
 
Year Ended September 30
 
2017
 
2016
 
2015
 
(Thousands)
U.S. Income (Loss) Before Income Taxes
$
443,991

 
$
(523,855
)
 
$
(698,977
)
Income Tax Expense (Benefit), Computed at U.S. Federal Statutory Rate of 35%
$
155,397

 
$
(183,349
)
 
$
(244,642
)
State Income Taxes (Benefit)
16,641

 
(39,697
)
 
(64,912
)
Federal Tax Credits
(6,679
)
 
(3,262
)
 
(732
)
Miscellaneous
(4,850
)
 
(6,589
)
 
(9,264
)
Total Income Taxes
$
160,509

 
$
(232,897
)
 
$
(319,550
)

The 2017 state income taxes (benefit) shown above includes income tax benefits related to state enhanced oil recovery tax credits and a decrease in the estimated state effective tax rates utilized in the calculation of deferred income taxes.
Significant components of the Company’s deferred tax liabilities and assets were as follows:
 
At September 30
 
2017
 
2016
 
(Thousands)
Deferred Tax Liabilities:
 
 
 
Property, Plant and Equipment
$
1,141,432

 
$
1,049,100

Pension and Other Post-Retirement Benefit Costs
79,516

 
151,903

Unrealized Hedging Gains
19,127

 
50,179

Other
57,919

 
55,457

Total Deferred Tax Liabilities
1,297,994

 
1,306,639

Deferred Tax Assets:
 
 
 
Pension and Other Post-Retirement Benefit Costs
(123,532
)
 
(195,829
)
Tax Loss and Credit Carryforwards
(200,344
)
 
(194,875
)
Other
(82,831
)
 
(92,140
)
Total Deferred Tax Assets
(406,707
)
 
(482,844
)
Total Net Deferred Income Taxes
$
891,287

 
$
823,795


As explained in Note A - Summary of Significant Accounting Policies under the heading "New Authoritative Accounting and Financial Reporting Guidance," the Company adopted authoritative guidance issued by the FASB simplifying several aspects of the accounting for stock-based compensation effective as of October 1, 2016. Under this guidance, the Company recognizes excess tax benefits as incurred. As of September 30, 2016, the table of deferred tax liabilities and assets shown above does not include deferred tax assets of $31.9 million that arose directly from excess tax benefits related to stock-based compensation in prior periods. This amount was recognized as a cumulative effect adjustment, increasing retained earnings at October 1, 2016.
Regulatory liabilities representing the reduction of previously recorded deferred income taxes associated with rate-regulated activities that are expected to be refundable to customers amounted to $95.7 million and $93.3 million at September 30, 2017 and 2016, respectively. Also, regulatory assets representing future amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded because of ratemaking practices, amounted to $181.4 million and $177.3 million at September 30, 2017 and 2016, respectively. Included in the above are regulatory liabilities and assets relating to the tax accounting method change noted below. The amounts are as follows: regulatory liabilities of $52.6 million as of September 30, 2017 and 2016 and regulatory assets of $99.4 million and $94.2 million as of September 30, 2017 and 2016, respectively.
The following is a reconciliation of the change in unrecognized tax benefits:
 
Year Ended September 30
 
2017
 
2016
 
2015
 
(Thousands)
Balance at Beginning of Year
$
396

 
$
5,085

 
$
3,147

Additions for Tax Positions of Prior Years
1,251

 
396

 
2,504

Reductions for Tax Positions of Prior Years
(396
)
 
(1,314
)
 
(566
)
Reductions Related to Settlements with Taxing Authorities

 
(3,771
)
 

Balance at End of Year
$
1,251

 
$
396

 
$
5,085


As a result of certain examinations in progress (discussed below), the Company anticipates the balance of unrecognized tax benefits could be reduced during the next 12 months. As of September 30, 2017, the entire balance of unrecognized tax benefits would favorably impact the effective tax rate, if recognized.
The IRS is currently conducting examinations of the Company for fiscal 2017 in accordance with the Compliance Assurance Process (“CAP”). The CAP audit employs a real time review of the Company’s books and tax records by the IRS that is intended to permit issue resolution prior to the filing of the tax return. The federal statute of limitations remains open for fiscal 2009 and later years. During fiscal 2009, consent was received from the IRS National Office approving the Company’s application to change its tax method of accounting for certain capitalized costs relating to its utility property. While local IRS examiners issued no-change reports for fiscal 2009 through 2016, the IRS has reserved the right to re-examine these years, pending the anticipated issuance of IRS guidance addressing the issue for natural gas utilities.
The Company is also subject to various routine state income tax examinations. The Company’s principal subsidiaries operate mainly in four states which have statutes of limitations that generally expire between three to four years from the date of filing of the income tax return.
As of September 30, 2017, the Company has the following carryforwards available:
Jurisdiction
 
Tax Attribute
 
Amount
(Thousands)
 
Expires
Federal
 
Net Operating Loss
 
$
184,289

 
2028-2033
Pennsylvania
 
Net Operating Loss
 
324,572

 
2030-2035
California
 
Net Operating Loss
 
169,723

 
2029-2035
Federal
 
Alternative Minimum Tax Credit
 
81,683

 
Unlimited
California
 
Alternative Minimum Tax Credit
 
5,873

 
Unlimited
Federal
 
Enhanced Oil Recovery Credit
 
10,502

 
2029-2037
California
 
Enhanced Oil Recovery Credit
 
5,061

 
2021-2037
Federal
 
R&D Tax Credit
 
5,694

 
2031-2036

Approximately $1.8 million of the federal Net Operating Loss carryforward is subject to certain annual limitations.
Subsequent to year-end, federal tax reform legislation was introduced which could have a material effect on the Company if enacted into law.
Capitalization And Short-Term Borrowings
Capitalization And Short-Term Borrowings
Capitalization and Short-Term Borrowings
Summary of Changes in Common Stock Equity
 
Common Stock
 
Paid In
Capital
 
Earnings
Reinvested
in the
Business
 
Accumulated
Other
Comprehensive
Income (Loss)
Shares
 
Amount
 
 
(Thousands, except per share amounts)
Balance at September 30, 2014
84,157

 
$
84,157

 
$
716,144

 
$
1,614,361

 
$
(3,979
)
Net Income (Loss) Available for Common Stock
 
 
 
 
 
 
(379,427
)
 
 
Dividends Declared on Common Stock ($1.56 Per Share)
 
 
 
 
 
 
(131,734
)
 
 
Other Comprehensive Income, Net of Tax
 
 
 
 
 
 
 
 
97,351

Share-Based Payment Expense(2)
 
 
 
 
2,207

 
 
 
 
Common Stock Issued Under Stock and Benefit Plans(1)
437

 
437

 
25,923

 
 
 
 
Balance at September 30, 2015
84,594

 
84,594

 
744,274

 
1,103,200

 
93,372

Net Income (Loss) Available for Common Stock
 
 
 
 
 
 
(290,958
)
 
 
Dividends Declared on Common Stock ($1.60 Per Share)
 
 
 
 
 
 
(135,881
)
 
 
Other Comprehensive Loss, Net of Tax
 
 
 
 
 
 
 
 
(99,012
)
Share-Based Payment Expense(2)
 
 
 
 
4,843

 
 
 
 
Common Stock Issued Under Stock and Benefit Plans(1)
525

 
525

 
22,047

 
 
 
 
Balance at September 30, 2016
85,119

 
85,119

 
771,164

 
676,361

 
(5,640
)
Net Income Available for Common Stock
 
 
 
 
 
 
283,482

 
 
Dividends Declared on Common Stock ($1.64 Per Share)
 
 
 
 
 
 
(140,090
)
 
 
Cumulative Effect of Adoption of Authoritative Guidance for Stock-Based Compensation
 
 
 
 
 
 
31,916

 
 
Other Comprehensive Loss, Net of Tax
 
 
 
 
 
 
 
 
(24,483
)
Share-Based Payment Expense(2)
 
 
 
 
10,902

 
 
 
 
Common Stock Issued Under Stock and Benefit Plans
424

 
424

 
14,580

 
 
 
 
Balance at September 30, 2017
85,543

 
$
85,543

 
$
796,646

 
$
851,669

(3)
$
(30,123
)
 
(1)
Paid in Capital includes tax benefits of $1.9 million and $9.1 million for September 30, 2016 and 2015, respectively, related to stock-based compensation.
(2)
Paid in Capital includes compensation costs associated with stock option, SARs, performance share and/or restricted stock awards. The expense is included within Net Income Available For Common Stock, net of tax benefits.
(3)
The availability of consolidated earnings reinvested in the business for dividends payable in cash is limited under terms of the indentures covering long-term debt. At September 30, 2017, $707.5 million of accumulated earnings was free of such limitations.
Common Stock
The Company has various plans which allow shareholders, employees and others to purchase shares of the Company common stock. The National Fuel Gas Company Direct Stock Purchase and Dividend Reinvestment Plan allows shareholders to reinvest cash dividends and make cash investments in the Company’s common stock and provides investors the opportunity to acquire shares of the Company common stock without the payment of any brokerage commissions in connection with such acquisitions. The 401(k) Plans allow employees the opportunity to invest in the Company common stock, in addition to a variety of other investment alternatives. Generally, at the discretion of the Company, shares purchased under these plans are either original issue shares purchased directly from the Company or shares purchased on the open market by an independent agent. During 2017, the Company issued 180,247 original issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan and 103,602 original issue shares of common stock for the Company's 401(k) plans.
During 2017, the Company issued 45,912 original issue shares of common stock as a result of stock option and SARs exercises, 80,530 original issue shares of common stock for restricted stock units that vested and 43,484 original issue shares of common stock for performance shares that vested. Holders of stock options, SARs, restricted share awards or restricted stock units will often tender shares of common stock to the Company for payment of option exercise prices and/or applicable withholding taxes. During 2017, 53,564 shares of common stock were tendered to the Company for such purposes. The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law.
The Company also has a director stock program under which it issues shares of Company common stock to the non-employee directors of the Company who receive compensation under the Company’s 2009 Non-Employee Director Equity Compensation Plan, as partial consideration for the directors’ services during the fiscal year. Under this program, the Company issued 24,028 original issue shares of common stock during 2017.
Shareholder Rights Plan
In 1996, the Company’s Board of Directors adopted a shareholder rights plan (Plan). The Plan has been amended several times since it was adopted and is now embodied in an Amended and Restated Rights Agreement effective December 4, 2008, a copy of which was included as an exhibit to the Form 8-K filed by the Company on December 4, 2008.
Pursuant to the Plan, the holders of the Company’s common stock have one right (Right) for each of their shares. Each Right is initially evidenced by the Company’s common stock certificates representing the outstanding shares of common stock.
The Rights have anti-takeover effects because they will cause substantial dilution of the Company’s common stock if a person (an Acquiring Person) attempts to acquire the Company on terms not approved by the Board of Directors.
The Rights become exercisable upon the occurrence of a Distribution Date as described below, but after a Distribution Date, Rights that are owned by an Acquiring Person will be null and void. At any time following a Distribution Date, each holder of a Right may exercise its right to receive, upon payment of an amount calculated under the Rights Agreement, common stock of the Company (or, under certain circumstances, other securities or assets of the Company) having a value equal to two times the amount paid to exercise the Right. However, the Rights are subject to redemption or exchange by the Company prior to their exercise as described below.
A Distribution Date would occur upon the earlier of (i) ten days after the public announcement that a person or group has acquired, or obtained the right to acquire, beneficial ownership of the Company’s common stock or other voting stock (including Synthetic Long Positions as defined in the Plan) having 10% or more of the total voting power of the Company’s common stock and other voting stock or (ii) ten days after the commencement or announcement by a person or group of an intention to make a tender or exchange offer that would result in that person acquiring, or obtaining the right to acquire, beneficial ownership of the Company’s common stock or other voting stock having 10% or more of the total voting power of the Company’s common stock and other voting stock.
In certain situations after a person or group has acquired beneficial ownership of 10% or more of the total voting power of the Company’s stock as described above, each holder of a Right will have the right to receive, upon exercise of the Right, common stock of the acquiring company having a value equal to two times the amount paid to exercise the Right. These situations would arise if the Company is acquired in a merger or other business combination or if 50% or more of the Company’s assets or earning power is sold or transferred.
At any time prior to the end of the business day on the tenth day following the Distribution Date, the Company may redeem the Rights in whole, but not in part, at a price of $0.005 per Right, payable in cash or stock. A decision to redeem the Rights requires the vote of 75% of the Company’s full Board of Directors. Also, at any time following the Distribution Date, 75% of the Company’s full Board of Directors may vote to exchange the Rights, in whole or in part, at an exchange rate of one share of common stock, or other property deemed to have the same value, per Right, subject to certain adjustments.
Upon exercise of the Rights, the Company may need additional regulatory approvals to satisfy the requirements of the Rights Agreement. The Rights will expire on July 31, 2018, unless earlier than that date, they are exchanged or redeemed or the Plan is amended to extend the expiration date.
Stock Option and Stock Award Plans
The Company has various stock option and stock award plans which provide or provided for the issuance of one or more of the following to key employees: incentive stock options, nonqualified stock options, SARs, restricted stock, restricted stock units, performance units or performance shares.
Stock-based compensation expense for the years ended September 30, 2017, 2016 and 2015 was approximately $10.8 million, $4.8 million and $2.1 million, respectively. Stock-based compensation expense is included in operation and maintenance expense on the Consolidated Statements of Income. The total income tax benefit related to stock-based compensation expense during the years ended September 30, 2017, 2016 and 2015 was approximately $4.4 million, $1.9 million and $0.9 million, respectively. A portion of stock-based compensation expense is subject to capitalization under IRS uniform capitalization rules. Stock-based compensation of $0.1 million, $0.1 million and $0.1 million was capitalized under these rules during the years ended September 30, 2017, 2016 and 2015, respectively. The tax benefit recognized from stock-based compensation exercises and vestings was $0.5 million for the year ended September 30, 2017.
Stock Options
Transactions involving option shares for all plans are summarized as follows:
 
Number of
Shares Subject
to Option
 
Weighted
Average
Exercise Price
 
Weighted
Average
Remaining
Contractual
Life (Years)
 
Aggregate
Intrinsic
Value
(In thousands)
Outstanding at September 30, 2016
19,000

 
$
39.48

 
 
 
 
Granted in 2017

 
$

 
 
 
 
Exercised in 2017
(19,000
)
 
$
39.48

 
 
 
 
Forfeited in 2017

 
$

 
 
 
 
Outstanding at September 30, 2017

 
$

 

 
$

Option shares exercisable at September 30, 2017

 
$

 

 
$

Shares available for future grant at September 30, 2017(1)
2,182,243

 
 
 
 
 
 
 
(1)
Includes shares available for options, SARs, restricted stock and performance share grants.
The total intrinsic value of stock options exercised during the years ended September 30, 2017, 2016 and 2015 totaled approximately $0.3 million, $4.1 million, and $5.1 million, respectively. For 2017, 2016 and 2015, the amount of cash received by the Company from the exercise of such stock options was approximately $0.8 million, $8.0 million, and $5.6 million, respectively. The Company last granted stock options in fiscal 2007 and all stock options have been fully vested since fiscal 2010.
SARs
Transactions involving SARs for all plans are summarized as follows:
 
Number of
Shares Subject
To Option
 
Weighted
Average
Exercise Price
 
Weighted
Average
Remaining
Contractual
Life (Years)
 
Aggregate
Intrinsic
Value
(In thousands)
Outstanding at September 30, 2016
1,590,988

 
$
48.19

 
 
 
 
Granted in 2017

 
$

 
 
 
 
Exercised in 2017
(82,077
)
 
$
39.77

 
 
 
 
Forfeited in 2017

 
$

 
 
 
 
Expired in 2017
(3,000
)
 
$
52.10

 
 
 
 
Outstanding at September 30, 2017
1,505,911

 
$
48.64

 
2.52
 
$
13,144

SARs exercisable at September 30, 2017
1,505,911

 
$
48.64

 
2.52
 
$
13,144

The Company did not grant any SARs during the years ended September 30, 2016 and 2015. The Company’s SARs include both performance based and non-performance based SARs, but the performance conditions associated with the performance based SARs at the time of grant have all been subsequently met. The SARs are considered equity awards under the current authoritative guidance for stock-based compensation. The accounting for SARs is the same as the accounting for stock options.
The total intrinsic value of SARs exercised during the years ended September 30, 2017, 2016 and 2015 totaled approximately $1.6 million, $0.4 million, and $2.0 million, respectively. For the years ended September 30, 2017, 2016 and 2015, 5,000 SARs, 113,082 SARs and 157,386 SARs, respectively, became fully vested. The total fair value of the SARs that became vested during each of the years ended September 30, 2017, 2016 and 2015 was approximately $0.1 million, $1.2 million and $1.7 million, respectively.
 
 
 
 
 
 

Restricted Share Awards
Transactions involving restricted share awards for all plans are summarized as follows: 
 
Number of
Restricted
Share Awards
 
Weighted Average
Fair Value per
Award
Outstanding at September 30, 2016
20,000

 
$
47.46

Granted in 2017

 
$

Vested in 2017

 
$

Forfeited in 2017

 
$

Outstanding at September 30, 2017
20,000

 
$
47.46


The Company did not grant any restricted share awards (non-vested stock as defined by the current accounting literature) during the years ended September 30, 2016 and 2015. As of September 30, 2017, unrecognized compensation expense related to restricted share awards totaled approximately $0.3 million, which will be recognized over a weighted average period of 3.1 years.
Vesting restrictions for the 20,000 outstanding shares of non-vested restricted stock at September 30, 2017 will lapse in 2021.
Restricted Stock Units
Transactions involving non-performance based restricted stock units for all plans are summarized as follows:
 
Number of
Restricted
Stock Units
 
Weighted Average
Fair Value per
Award
Outstanding at September 30, 2016
239,151

 
$
49.67

Granted in 2017
87,143

 
$
52.13

Vested in 2017
(80,530
)
 
$
53.38

Forfeited in 2017
(12,565
)
 
$
53.75

Outstanding at September 30, 2017
233,199

 
$
48.99


The Company also granted 101,943 and 88,899 non-performance based restricted stock units during the years ended September 30, 2016 and 2015, respectively. The weighted average fair value of such non-performance based restricted stock units granted in 2016 and 2015 was $35.89 per share and $64.04 per share, respectively. As of September 30, 2017, unrecognized compensation expense related to non-performance based restricted stock units totaled approximately $4.7 million, which will be recognized over a weighted average period of 2.2 years.
Vesting restrictions for the non-performance based restricted stock units outstanding at September 30, 2017 will lapse as follows: 2018 — 73,819 units; 2019 — 65,265 units; 2020 — 52,641 units; 2021 - 27,976 units; and 2022 - 13,498 units.


Performance Shares
Transactions involving performance shares for all plans are summarized as follows:
 
Number of
Performance
Shares
 
Weighted Average
Fair Value per
Award
Outstanding at September 30, 2016
438,234

 
$
44.98

Granted in 2017
184,148

 
$
56.39

Vested in 2017
(43,484
)
 
$
69.13

Forfeited in 2017
(51,150
)
 
$
60.74

Outstanding at September 30, 2017
527,748

 
$
45.44


The Company also granted 309,996 and 107,044 performance shares during the years ended September 30, 2016 and 2015, respectively. The weighted average grant date fair value of such performance shares granted in 2016 and 2015 was $30.71 per share and $65.26 per share, respectively. As of September 30, 2017, unrecognized compensation expense related to performance shares totaled approximately $10.1 million, which will be recognized over a weighted average period of 1.7 years. Vesting restrictions for the outstanding performance shares at September 30, 2017 will lapse as follows: 2018 - 88,132 shares; 2019 - 255,468 shares; and 2020 - 184,148 shares.
Half of the performance shares granted during the year ended September 30, 2017 must meet a performance goal related to relative return on capital over the performance cycle of October 1, 2016 to September 30, 2019. In addition, half of the performance shares granted during the year ended September 30, 2016 must meet a performance goal related to relative return on capital over the performance cycle of October 1, 2015 to September 30, 2018, and half of the performance shares granted during the year ended September 30, 2015 must meet a performance goal related to relative return on capital over the performance cycle of October 1, 2014 to September 30, 2017.  The performance goals over their respective performance cycles for these performance shares granted during 2017, 2016 and 2015 is the Company’s total return on capital relative to the total return on capital of other companies in a group selected by the Compensation Committee (“Report Group”).  Total return on capital for a given company means the average of the Report Group companies’ returns on capital for each twelve month period corresponding to each of the Company’s fiscal years during the performance cycle, based on data reported for the Report Group companies in the Bloomberg database.  The number of these performance shares that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company.  The fair value of these performance shares is calculated by multiplying the expected number of shares that will be issued by the average market price of Company common stock on the date of grant reduced by the present value of forgone dividends over the vesting term of the award.  The fair value is recorded as compensation expense over the vesting term of the award.  
The other half of the performance shares granted during the year ended September 30, 2017 must meet a performance goal related to relative total shareholder return over the performance cycle of October 1, 2016 to September 30, 2019. In addition, the other half of the performance shares granted during the year ended September 30, 2016 must meet a performance goal related to relative total shareholder return over the performance cycle of October 1, 2015 to September 30, 2018, and the other half of the performance shares granted during the year ended September 30, 2015 must meet a performance goal related to relative total shareholder return over the performance cycle of October 1, 2014 to September 30, 2017.  The performance goals over their respective performance cycles for these total shareholder return performance shares ("TSR performance shares") granted during 2017, 2016 and 2015 is the Company’s three-year total shareholder return relative to the three-year total shareholder return of the other companies in the Report Group.  Three-year shareholder return for a given company will be based on the data reported for that company (with the starting and ending stock prices over the performance cycle calculated as the average closing stock price for the prior calendar month and with dividends reinvested in that company’s securities at each ex-dividend date) in the Bloomberg database.  The number of these TSR performance shares that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company.  The fair value price at the date of grant for the TSR performance shares is determined using a Monte Carlo simulation technique, which includes a reduction in value for the present value of forgone dividends over the vesting term of the award.  This price is multiplied by the number of TSR performance shares awarded, the result of which is recorded as compensation expense over the vesting term of the award. In calculating the fair value of the award, the risk-free interest rate is based on the yield of a Treasury Note with a term commensurate with the remaining term of the TSR performance shares. The remaining term is based on the remainder of the performance cycle as of the date of grant. The expected volatility is based on historical daily stock price returns. For the TSR performance shares, it was assumed that there would be no forfeitures, based on the vesting term and the number of grantees. The following assumptions were used in estimating the fair value of the TSR performance shares at the date of grant:
 
Year Ended September 30
 
2017
 
2016
 
2015
Risk-Free Interest Rate
1.54
%
 
1.26
%
 
1.01
%
Remaining Term at Date of Grant (Years)
2.79

 
2.79

 
2.78

Expected Volatility
22.6
%
 
20.5
%
 
20.1
%
Expected Dividend Yield (Quarterly)
N/A

 
N/A

 
N/A


Redeemable Preferred Stock
As of September 30, 2017, there were 10,000,000 shares of $1 par value Preferred Stock authorized but unissued.
Long-Term Debt
The outstanding long-term debt is as follows:
 
At September 30
 
2017
 
2016
 
(Thousands)
Medium-Term Notes(1):
 
 
 
7.4% due March 2023 to June 2025
$
99,000

 
$
99,000

Notes(1)(3)(4):
 
 
 
3.75% to 8.75% due April 2018 to September 2027
2,300,000

 
2,000,000

Total Long-Term Debt
2,399,000

 
2,099,000

Less Unamortized Discount and Debt Issuance Costs
15,319

 
12,748

Less Current Portion(2)
300,000

 

 
$
2,083,681

 
$
2,086,252

 
(1)
The Medium-Term Notes and Notes are unsecured.
(2)
Current Portion of Long-Term Debt at September 30, 2017 consisted of $300.0 million of 6.50% notes scheduled to mature in April 2018. The Company redeemed these notes on October 18, 2017 for $307.0 million, plus accrued interest. The call premium was recorded to Unamortized Debt Expense on the Consolidated Balance Sheet in October 2017.
(3)
The holders of these notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade.
(4)
The interest rate payable on $300.0 million of 3.95% notes will be subject to adjustment from time to time, with a maximum of 2.00%, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to below investment grade (or if the credit rating assigned to the notes is subsequently upgraded).
On September 18, 2017, the Company issued $300.0 million of 3.95% notes due September 15, 2027. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $295.2 million. The proceeds of this debt issuance were used to redeem $300.0 million of 6.50% notes in October 2017.
As of September 30, 2017, the aggregate principal amounts of long-term debt maturing during the next five years and thereafter are as follows: $300.0 million in 2018, $250.0 million in 2019, zero in 2020 and 2021, $500.0 million in 2022, and $1,349.0 million thereafter.
Short-Term Borrowings
The Company historically has obtained short-term funds either through bank loans or the issuance of commercial paper. On September 9, 2016, the Company entered into a Third Amended and Restated Credit Agreement (Credit Agreement) with a syndicate of what now numbers 13 banks. This Credit Agreement provides a $750.0 million multi-year unsecured committed revolving credit facility through December 5, 2019. The Credit Agreement also provided a $500.0 million 364-day unsecured committed revolving credit facility with 11 of the 13 banks, which expired on September 8, 2017 and was not subsequently renewed. The Company also has a number of individual uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. Borrowings under the uncommitted lines of credit are made at competitive market rates. The uncommitted credit lines are revocable at the option of the financial institutions and are reviewed on an annual basis. The Company anticipates that its uncommitted lines of credit generally will be renewed or substantially replaced by similar lines. The total amount available to be issued under the Company’s commercial paper program is $500.0 million. At September 30, 2017, the commercial paper program was backed by the Credit Agreement.
The Company did not have any outstanding commercial paper or short term notes payable to banks at September 30, 2017 and 2016.
Debt Restrictions
The Credit Agreement provides that the Company's debt to capitalization ratio will not exceed .675 at the last day of any fiscal quarter through September 30, 2017, or .65 at the last day of any fiscal quarter from October 1, 2017 through December 5, 2019. At September 30, 2017, the Company’s debt to capitalization ratio (as calculated under the facility) was .58. The constraints specified in the Credit Agreement would have permitted an additional $1.15 billion in short-term and/or long-term debt to be outstanding (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio exceeded .675.
A downgrade in the Company’s credit ratings could increase borrowing costs, negatively impact the availability of capital from banks, commercial paper purchasers and other sources, and require the Company's subsidiaries to post letters of credit, cash or other assets as collateral with certain counterparties. If the Company is not able to maintain investment-grade credit ratings, it may not be able to access commercial paper markets. However, the Company expects that it could borrow under its credit facilities or rely upon other liquidity sources, including cash provided by operations.
The Credit Agreement contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $40.0 million or more, or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity. As of September 30, 2017, the Company had no debt outstanding under the Credit Agreement.
Under the Company’s existing indenture covenants, at September 30, 2017, the Company would have been permitted to issue up to a maximum of $126.0 million in additional long-term indebtedness at then current market interest rates in addition to being able to issue new indebtedness to replace maturing debt. However, if the Company were to experience a significant loss in the future (for example, as a result of an impairment of oil and gas properties), it is possible, depending on factors including the magnitude of the loss, that these indenture covenants would restrict the Company's ability to issue additional long-term unsecured indebtedness for a period of up to nine calendar months, beginning with the fourth calendar month following the loss. This would not preclude the Company from issuing new indebtedness to replace maturing debt. The Company's present liquidity position is believed to be adequate to satisfy known demands.
The Company’s 1974 indenture pursuant to which $98.7 million (or 4.1%) of the Company’s long-term debt (as of September 30, 2017) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement, or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.
Fair Value Measurements
Fair Value Measurements
Fair Value Measurements
The FASB authoritative guidance regarding fair value measurements establishes a fair-value hierarchy and prioritizes the inputs used in valuation techniques that measure fair value. Those inputs are prioritized into three levels. Level 1 inputs are unadjusted quoted prices in active markets for assets or liabilities that the Company can access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly at the measurement date. Level 3 inputs are unobservable inputs for the asset or liability at the measurement date. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities (as applicable) that were accounted for at fair value on a recurring basis as of September 30, 2017 and 2016. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The fair value presentation for over-the-counter swaps combines gas and oil swaps because a significant number of the counterparties enter into both gas and oil swap agreements with the Company. 
 
At Fair Value as of September 30, 2017
Recurring Fair Value Measures
Level 1
 
Level 2
 
Level 3
 
Netting
Adjustments(1)
 
Total(1)
 
(Dollars in thousands)
Assets:
 
 
 
 
 
 
 
 
 
Cash Equivalents — Money Market Mutual Funds
$
527,978

 
$

 
$

 
$

 
$
527,978

Derivative Financial Instruments:
 
 
 
 
 
 
 
 
 
Commodity Futures Contracts — Gas
1,483

 

 

 
(963
)
 
520

Over the Counter Swaps — Gas and Oil

 
38,977

 

 
(4,206
)
 
34,771

Foreign Currency Contracts

 
1,227

 

 
(407
)
 
820

Other Investments:
 
 
 
 
 
 
 
 

Balanced Equity Mutual Fund
37,033

 

 

 

 
37,033

Fixed Income Mutual Fund
45,727

 

 

 

 
45,727

Common Stock — Financial Services Industry
3,150

 

 

 

 
3,150

Hedging Collateral Deposits
1,741

 

 

 

 
1,741

Total
$
617,112

 
$
40,204

 
$

 
$
(5,576
)
 
$
651,740

Liabilities:
 
 
 
 
 
 
 
 
 
Derivative Financial Instruments:
 
 
 
 
 
 
 
 
 
Commodity Futures Contracts — Gas
$
963

 
$

 
$

 
$
(963
)
 
$

Over the Counter Swaps — Gas and Oil

 
5,309

 

 
(4,206
)
 
1,103

Foreign Currency Contracts

 
407

 

 
(407
)
 

Total
$
963

 
$
5,716

 
$

 
$
(5,576
)
 
$
1,103

Total Net Assets/(Liabilities)
$
616,149

 
$
34,488

 
$

 
$

 
$
650,637


 
At Fair Value as of September 30, 2016
Recurring Fair Value Measures
Level 1
 
Level 2
 
Level 3
 
Netting
Adjustments(1)
 
Total(1)
 
(Dollars in thousands)
Assets:
 
 
 
 
 
 
 
 
 
Cash Equivalents — Money Market Mutual Funds
$
113,407

 
$

 
$

 
$

 
$
113,407

Derivative Financial Instruments:
 
 
 
 
 
 
 
 
 
Commodity Futures Contracts — Gas
2,623

 

 

 
(2,276
)
 
347

Over the Counter Swaps — Gas and Oil

 
119,654

 

 
(3,860
)
 
115,794

Foreign Currency Contracts

 

 

 
(2,337
)
 
(2,337
)
Other Investments:
 
 
 
 
 
 
 
 
 
Balanced Equity Mutual Fund
36,658

 

 

 

 
36,658

Fixed Income Mutual Fund
31,395

 

 

 

 
31,395

Common Stock — Financial Services Industry
2,902

 

 

 

 
2,902

Hedging Collateral Deposits
1,484

 

 

 

 
1,484

Total
$
188,469


$
119,654


$


$
(8,473
)

$
299,650

Liabilities:
 
 
 
 
 
 
 
 
 
Derivative Financial Instruments:
 
 
 
 
 
 
 
 
 
Commodity Futures Contracts — Gas
$
2,276

 
$

 
$

 
$
(2,276
)
 
$

Over the Counter Swaps — Gas and Oil

 
5,322

 

 
(3,860
)
 
1,462

Foreign Currency Contracts

 
2,337

 

 
(2,337
)
 

Total
$
2,276

 
$
7,659

 
$

 
$
(8,473
)
 
$
1,462

Total Net Assets/(Liabilities)
$
186,193

 
$
111,995

 
$

 
$

 
$
298,188

 
(1)
Netting Adjustments represent the impact of legally-enforceable master netting arrangements that allow the Company to net gain and loss positions held with the same counterparties. The net asset or net liability for each counterparty is recorded as an asset or liability on the Company’s balance sheet.
Derivative Financial Instruments
At September 30, 2017 and 2016, the derivative financial instruments reported in Level 1 consist of natural gas NYMEX and ICE futures contracts used in the Company’s Energy Marketing segment. Hedging collateral deposits of $1.7 million (at September 30, 2017) and $1.5 million (at September 30, 2016), which are associated with these futures contracts, have been reported in Level 1 as well. The derivative financial instruments reported in Level 2 at September 30, 2017 and 2016 consist of natural gas price swap agreements used in the Company’s Exploration and Production and Energy Marketing segments, the majority of the crude oil price swap agreements used in the Company’s Exploration and Production segment and foreign currency contracts used in the Company's Exploration and Production segment. The fair value of the Level 2 price swap agreements is based on an internal, discounted cash flow model that uses observable inputs (i.e. LIBOR based discount rates and basis differential information, if applicable, at active natural gas and crude oil trading markets). The fair value of the Level 2 foreign currency contracts is determined using the market approach based on observable market transactions of forward Canadian currency rates.
The accounting rules for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At September 30, 2017, the Company determined that nonperformance risk would have no material impact on its financial position or results of operation. To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates.
For the years ended September 30, 2017 and 2016, there were no assets or liabilities measured at fair value and classified as Level 3. The Company's Exploration and Production segment had a small portion of their crude oil price swap agreements reported as Level 3 at October 1, 2015 that settled during the first quarter of fiscal 2016. For the years ended September 30, 2017 and September 30, 2016, no transfers in or out of Level 1 or Level 2 occurred.
Financial Instruments
Financial Instruments
Financial Instruments
Long-Term Debt
The fair market value of the Company’s debt, as presented in the table below, was determined using a discounted cash flow model, which incorporates the Company’s credit ratings and current market conditions in determining the yield, and subsequently, the fair market value of the debt. Based on these criteria, the fair market value of long-term debt, including current portion, was as follows:
 
 
At September 30
 
2017 Carrying
Amount
 
2017 Fair
Value
 
2016 Carrying
Amount
 
2016 Fair
Value
 
(Thousands)
Long-Term Debt
$
2,383,681

 
$
2,523,639

 
$
2,086,252

 
$
2,255,562


The fair value amounts are not intended to reflect principal amounts that the Company will ultimately be required to pay. Carrying amounts for other financial instruments recorded on the Company’s Consolidated Balance Sheets approximate fair value. The fair value of long-term debt was calculated using observable inputs (U.S. Treasuries/LIBOR for the risk-free component and company specific credit spread information — generally obtained from recent trade activity in the debt). As such, the Company considers the debt to be Level 2.
Any temporary cash investments, notes payable to banks and commercial paper are stated at cost. Temporary cash investments are considered Level 1, while notes payable to banks and commercial paper are considered to be Level 2. Given the short-term nature of the notes payable to banks and commercial paper, the Company believes cost is a reasonable approximation of fair value.
Other Investments
Investments in life insurance are stated at their cash surrender values or net present value as discussed below. Investments in an equity mutual fund, a fixed income mutual fund and the stock of an insurance company (marketable equity securities), as discussed below, are stated at fair value based on quoted market prices.
Other investments include cash surrender values of insurance contracts (net present value in the case of split-dollar collateral assignment arrangements) and marketable equity and fixed income securities. The values of the insurance contracts amounted to $39.4 million and $39.7 million at September 30, 2017 and 2016, respectively. The fair value of the equity mutual fund was $37.0 million and $36.7 million at September 30, 2017 and 2016, respectively. The gross unrealized gain on this equity mutual fund was $9.9 million at September 30, 2017 and $7.9 million at September 30, 2016. The fair value of the fixed income mutual fund was $45.7 million and $31.4 million at September 30, 2017 and 2016, respectively. The gross unrealized loss on this fixed income mutual fund was less than $0.1 million at September 30, 2017 and the gross unrealized gain on this fixed income mutual fund was less than $0.1 million at September 30, 2016. The fair value of the stock of an insurance company was $3.2 million and $2.9 million at September 30, 2017 and 2016, respectively. The gross unrealized gain on this stock was $2.2 million and $1.6 million at September 30, 2017 and 2016, respectively. The insurance contracts and marketable equity and fixed income securities are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees.
Derivative Financial Instruments
The Company uses derivative financial instruments to manage commodity price risk in the Exploration and Production segment as well as the Energy Marketing segment. The Company enters into futures contracts and over-the-counter swap agreements for natural gas and crude oil to manage the price risk associated with forecasted sales of gas and oil. In addition, the Company also enters into foreign exchange forward contracts to manage the risk of currency fluctuations associated with transportation costs denominated in Canadian currency in the Exploration and Production segment. These instruments are accounted for as cash flow hedges. The Company also enters into futures contracts and swaps, which are accounted for as cash flow hedges, to manage the price risk associated with forecasted gas purchases. The Company enters into futures contracts and swaps to mitigate risk associated with fixed price sales commitments, fixed price purchase commitments, and the decline in value of natural gas held in storage. These instruments are accounted for as fair value hedges. The length of the Company’s combined cash flow and fair value hedges does not typically exceed 6 years while the foreign currency forward contracts do not exceed 9 years. The Exploration and Production segment holds the majority of the Company’s derivative financial instruments.
The Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at September 30, 2017 and September 30, 2016. Substantially all of the derivative financial instruments reported on those line items relate to commodity contracts and a small portion relates to foreign currency forward contracts.
Cash Flow Hedges
For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income (loss) and reclassified into earnings in the period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.
As of September 30, 2017, the Company had the following commodity derivative contracts (swaps and futures contracts) outstanding:
Commodity
Units

 
Natural Gas
114.3

 Bcf (short positions)
Natural Gas
1.0

 Bcf (long positions)
Crude Oil
3,459,000

 Bbls (short positions)
As of September 30, 2017, the Company was hedging a total of $89.2 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts (long positions).
As of September 30, 2017, the Company had $35.5 million ($20.8 million after tax) of net hedging gains included in the accumulated other comprehensive income (loss) balance. It is expected that $18.0 million ($10.6 million after tax) of such unrealized gains will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged transactions are recorded in earnings.
The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Year Ended September 30, 2017 and 2016 (Dollar Amounts in Thousands)
Derivatives in Cash
Flow Hedging
Relationships
 
Amount of
Derivative Gain or
(Loss) Recognized
in Other
Comprehensive
Income (Loss) on
the Consolidated
Statement of
Comprehensive
Income (Loss)
(Effective Portion)
for the Year Ended
September 30,
 
Location of
Derivative Gain or (Loss) Reclassified
from Accumulated
Other Comprehensive
Income (Loss) on
the Consolidated
Balance Sheet into the Consolidated
Statement of Income
(Effective Portion)
 
Amount of
Derivative Gain or
(Loss) Reclassified
from Accumulated
Other
Comprehensive
Income (Loss) on
the Consolidated
Balance Sheet into
the Consolidated
Statement of Income
(Effective Portion)
for the Year Ended
September 30,
 
Location of
Derivative Gain or (Loss) Recognized
in the Consolidated
Statement of Income
(Ineffective Portion
and Amount
Excluded from
Effectiveness Testing)
 
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness  Testing) for the Year Ended September 30,
 
 
2017
 
2016
 
 
 
2017
 
2016
 
 
 
2017
 
2016
Commodity Contracts
 
$
2,811

 
$
58,714

 
Operating Revenue
 
$
83,983

 
$
216,823

 
Operating Revenue
 
$
(100
)
 
$
392

Commodity Contracts
 
(164
)
 
1,585

 
Purchased Gas
 
(1,921
)
 
4,520

 
Not Applicable
 

 

Foreign Currency Contracts
 
2,700

 
194

 
Operation and Maintenance Expense
 
(457
)
 
(424
)
 
Not Applicable
 

 

Total
 
$
5,347

 
$
60,493

 
 
 
$
81,605

 
$
220,919

 
 
 
$
(100
)
 
$
392

Fair Value Hedges
The Company utilizes fair value hedges to mitigate risk associated with fixed price sales commitments, fixed price purchase commitments, and the decline in the value of certain natural gas held in storage. With respect to fixed price sales commitments, the Company enters into long positions to mitigate the risk of price increases for natural gas supplies that could occur after the Company enters into fixed price sales agreements with its customers. With respect to fixed price purchase commitments, the Company enters into short positions to mitigate the risk of price decreases that could occur after the Company locks into fixed price purchase deals with its suppliers. With respect to storage hedges, the Company enters into short positions to mitigate the risk of price decreases that could result in a lower of cost or net realizable value writedown of the value of natural gas in storage that is recorded in the Company’s financial statements. As of September 30, 2017, the Company’s Energy Marketing segment had fair value hedges covering approximately 17.5 Bcf (16.4 Bcf of fixed price sales commitments and 1.1 Bcf of commitments related to the withdrawal of storage gas). For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk completely offset each other in current earnings, as shown below.
Derivatives in Fair Value Hedging Relationships
 
Location of Gain or (Loss) on Derivative and Hedged Item Recognized in the Consolidated Statement of Income
 
Amount of Gain or
(Loss) on Derivative
Recognized in the
Consolidated
Statement of Income
for the Year Ended
September 30, 2017
 
Amount of Gain or
(Loss) on Hedged Item
Recognized in the
Consolidated
Statement of Income
for the Year Ended
September 30, 2017
 
 
 
 
(In thousands)
Commodity Contracts
 
Operating Revenues
 
$
1,655

 
$
(1,655
)
Commodity Contracts
 
Purchased Gas
 
464

 
(464
)
 
 
 
 
$
2,119

 
$
(2,119
)

Credit Risk
The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on a quarterly basis monitors counterparty credit exposure. The majority of the Company’s counterparties are financial institutions and energy traders. The Company has over-the-counter swap positions and applicable foreign currency forward contracts with seventeen counterparties of which sixteen are in a net gain position. On average, the Company had $2.2 million of credit exposure per counterparty in a gain position at September 30, 2017. The maximum credit exposure per counterparty in a gain position at September 30, 2017 was $6.0 million. As of September 30, 2017, no collateral was received from the counterparties by the Company. The Company's gain position on such derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral, nor had the counterparties' credit ratings declined to levels at which the counterparties were required to post collateral.
As of September 30, 2017, fourteen of the seventeen counterparties to the Company’s outstanding derivative instrument contracts (specifically the over-the-counter swaps and applicable foreign currency forward contracts) had a common credit-risk related contingency feature. In the event the Company’s credit rating increases or falls below a certain threshold (applicable debt ratings), the available credit extended to the Company would either increase or decrease. A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments). If the Company’s outstanding derivative instrument contracts were in a liability position (or if the liability were larger) and/or the Company’s credit rating declined, then additional hedging collateral deposits may be required. At September 30, 2017, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $26.0 million according to the Company’s internal model (discussed in Note F — Fair Value Measurements). For its over-the-counter swap agreements and foreign currency forward contracts, no hedging collateral deposits were required to be posted by the Company at September 30, 2017.
For its exchange traded futures contracts, the Company was required to post $1.7 million in hedging collateral deposits as of September 30, 2017. As these are exchange traded futures contracts, there are no specific credit-risk related contingency features. The Company posts or receives hedging collateral based on open positions and margin requirements it has with its counterparties.
The Company’s requirement to post hedging collateral deposits and the Company's right to receive hedging collateral deposits is based on the fair value determined by the Company’s counterparties, which may differ from the Company’s assessment of fair value. Hedging collateral deposits may also include closed derivative positions in which the broker has not cleared the cash from the account to offset the derivative liability. The Company records liabilities related to closed derivative positions in Other Accruals and Current Liabilities on the Consolidated Balance Sheet. These liabilities are relieved when the broker clears the cash from the hedging collateral deposit account. This is discussed in Note A under Hedging Collateral Deposits.
Retirement Plan And Other Post-Retirement Benefits
Retirement Plan And Other Post-Retirement Benefits
Retirement Plan and Other Post-Retirement Benefits
The Company has a tax-qualified, noncontributory, defined-benefit retirement plan (Retirement Plan). The Retirement Plan covers certain non-collectively bargained employees hired before July 1, 2003 and certain collectively bargained employees hired before November 1, 2003. Certain non-collectively bargained employees hired after June 30, 2003 and certain collectively bargained employees hired after October 31, 2003 are eligible for a Retirement Savings Account benefit provided under the Company’s defined contribution Tax-Deferred Savings Plans. Costs associated with the Retirement Savings Account were $2.9 million, $2.6 million and $2.3 million for the years ended September 30, 2017, 2016 and 2015, respectively. Costs associated with the Company’s contributions to the Tax-Deferred Savings Plans, exclusive of the costs associated with the Retirement Savings Account, were $5.9 million, $5.9 million, and $5.8 million for the years ended September 30, 2017, 2016 and 2015, respectively.
The Company provides health care and life insurance benefits (other post-retirement benefits) for a majority of its retired employees. The other post-retirement benefits cover certain non-collectively bargained employees hired before January 1, 2003 and certain collectively bargained employees hired before October 31, 2003.
The Company’s policy is to fund the Retirement Plan with at least an amount necessary to satisfy the minimum funding requirements of applicable laws and regulations and not more than the maximum amount deductible for federal income tax purposes. The Company has established VEBA trusts for its other post-retirement benefits. Contributions to the VEBA trusts are tax deductible, subject to limitations contained in the Internal Revenue Code and regulations and are made to fund employees’ other post-retirement benefits, as well as benefits as they are paid to current retirees. In addition, the Company has established 401(h) accounts for its other post-retirement benefits. They are separate accounts within the Retirement Plan trust used to pay retiree medical benefits for the associated participants in the Retirement Plan. Although these accounts are in the Retirement Plan trust, for funding status purposes as shown below, the 401(h) accounts are included in Fair Value of Assets under Other Post-Retirement Benefits. Contributions are tax-deductible when made, subject to limitations contained in the Internal Revenue Code and regulations.
The expected return on Retirement Plan assets, a component of net periodic benefit cost shown in the tables below, is applied to the market-related value of plan assets. The market-related value of plan assets is the market value as of the measurement date adjusted for variances between actual returns and expected returns (from previous years) that have not been reflected in net periodic benefit costs. The expected return on other post-retirement benefit assets (i.e. the VEBA trusts and 401(h) accounts), which is a component of net periodic benefit cost shown in the tables below, is applied to the fair value of assets as of the measurement date.
Reconciliations of the Benefit Obligations, Plan Assets and Funded Status, as well as the components of Net Periodic Benefit Cost and the Weighted Average Assumptions of the Retirement Plan and other post-retirement benefits are shown in the tables below. The date used to measure the Benefit Obligations, Plan Assets and Funded Status is September 30 for fiscal years 2017, 2016 and 2015.
 
Retirement Plan
 
Other Post-Retirement Benefits
 
Year Ended September 30
 
Year Ended September 30
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
 
(Thousands)
Change in Benefit Obligation
 
 
 
 
 
 
 
 
 
 
 
Benefit Obligation at Beginning of Period
$
1,097,421

 
$
1,026,190

 
$
999,499

 
$
526,138

 
$
464,987

 
$
465,583

Service Cost
11,969

 
11,710

 
12,047

 
2,449

 
2,331

 
2,693

Interest Cost
38,383

 
42,315

 
41,217

 
19,007

 
20,386

 
19,285

Plan Participants’ Contributions

 

 

 
2,717

 
2,558

 
2,242

Retiree Drug Subsidy Receipts

 

 

 
1,553

 
1,925

 
1,338

Amendments(1)

 

 
7,752

 

 

 

Actuarial (Gain) Loss
(32,466
)
 
76,309

 
23,426

 
(62,215
)
 
60,402

 
(1,575
)
Benefits Paid
(60,481
)
 
(59,103
)
 
(57,751
)
 
(27,030
)
 
(26,451
)
 
(24,579
)
Benefit Obligation at End of Period
$
1,054,826

 
$
1,097,421

 
$
1,026,190

 
$
462,619

 
$
526,138

 
$
464,987

Change in Plan Assets
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Assets at Beginning of Period
$
869,775

 
$
834,870

 
$
869,791

 
$
494,320

 
$
477,959

 
$
497,601

Actual Return on Plan Assets
84,279

 
87,008

 
(13,370
)
 
40,157

 
37,415

 
534

Employer Contributions
17,146

 
7,000

 
36,200

 
3,853

 
2,839

 
2,161

Plan Participants’ Contributions

 

 

 
2,717

 
2,558

 
2,242

Benefits Paid
(60,481
)
 
(59,103
)
 
(57,751
)
 
(27,030
)
 
(26,451
)
 
(24,579
)
Fair Value of Assets at End of Period
$
910,719

 
$
869,775

 
$
834,870

 
$
514,017

 
$
494,320

 
$
477,959

Net Amount Recognized at End of Period (Funded Status)
$
(144,107
)
 
$
(227,646
)
 
$
(191,320
)
 
$
51,398

 
$
(31,818
)
 
$
12,972

Amounts Recognized in the Balance Sheets Consist of:
 
 
 
 
 
 
 
 
 
 
 
Non-Current Liabilities
$
(144,107
)
 
$
(227,646
)
 
$
(191,320
)
 
$
(4,972
)
 
$
(49,467
)
 
$
(11,487
)
Non-Current Assets

 

 

 
56,370

 
17,649

 
24,459

Net Amount Recognized at End of Period
$
(144,107
)
 
$
(227,646
)
 
$
(191,320
)
 
$
51,398

 
$
(31,818
)
 
$
12,972

Accumulated Benefit Obligation
$
1,010,179

 
$
1,039,408

 
$
968,984

 
N/A

 
N/A

 
N/A

Weighted Average Assumptions Used to Determine Benefit Obligation at September 30
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
3.77
%
 
3.60
%
 
4.25
%
 
3.81
%
 
3.70
%
 
4.50
%
Rate of Compensation Increase
4.70
%
 
4.70
%
 
4.75
%
 
4.70
%
 
4.70
%
 
4.75
%
 
Retirement Plan
 
Other Post-Retirement Benefits
 
Year Ended September 30
 
Year Ended September 30
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
 
(Thousands)
Components of Net Periodic Benefit Cost
 
 
 
 
 
 
 
 
 
 
 
Service Cost
$
11,969

 
$
11,710

 
$
12,047

 
$
2,449

 
$
2,331

 
$
2,693

Interest Cost
38,383

 
42,315

 
41,217

 
19,007

 
20,386

 
19,285

Expected Return on Plan Assets
(59,718
)
 
(59,369
)
 
(59,615
)
 
(31,458
)
 
(31,535
)
 
(34,089
)
Amortization of Prior Service Cost (Credit)
1,058

 
1,234

 
183

 
(429
)
 
(912
)
 
(1,913
)
Recognition of Actuarial Loss(2)
42,687

 
32,248

 
36,129

 
18,415

 
5,530

 
4,148

Net Amortization and Deferral for Regulatory Purposes
469

 
3,957

 
7,739

 
6,108

 
17,123

 
20,322

Net Periodic Benefit Cost
$
34,848

 
$
32,095

 
$
37,700

 
$
14,092

 
$
12,923

 
$
10,446

Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
3.60
%
 
4.25
%
 
4.25
%
 
3.70
%
 
4.50
%
 
4.25
%
Expected Return on Plan Assets
7.00
%
 
7.25
%
 
7.50
%
 
6.50
%
 
6.75
%
 
7.00
%
Rate of Compensation Increase
4.75
%
 
4.75
%
 
4.75
%
 
4.75
%
 
4.75
%
 
4.75
%
 
(1)
In fiscal 2015, the Company passed an amendment which updated the mortality table used in the Retirement Plan's definition of "actuarially equivalent" effective July 1, 2015. This increased the benefit obligation of the Retirement Plan.
(2)
Distribution Corporation’s New York jurisdiction calculates the amortization of the actuarial loss on a vintage year basis over 10 years, as mandated by the NYPSC. All the other subsidiaries of the Company utilize the corridor approach.
The Net Periodic Benefit Cost in the table above includes the effects of regulation. The Company recovers pension and other post-retirement benefit costs in its Utility and Pipeline and Storage segments in accordance with the applicable regulatory commission authorizations. Certain of those commission authorizations established tracking mechanisms which allow the Company to record the difference between the amount of pension and other post-retirement benefit costs recoverable in rates and the amounts of such costs as determined under the existing authoritative guidance as either a regulatory asset or liability, as appropriate. Any activity under the tracking mechanisms (including the amortization of pension and other post-retirement regulatory assets and liabilities) is reflected in the Net Amortization and Deferral for Regulatory Purposes line item above.
In addition to the Retirement Plan discussed above, the Company also has Non-Qualified benefit plans that cover a group of management employees designated by the Chief Executive Officer of the Company. These plans provide for defined benefit payments upon retirement of the management employee, or to the spouse upon death of the management employee. The net periodic benefit costs associated with these plans were $7.6 million, $7.5 million and $7.0 million in 2017, 2016 and 2015, respectively. The accumulated benefit obligations for the plans were $72.5 million, $72.4 million and $66.0 million at September 30, 2017, 2016 and 2015, respectively. The projected benefit obligations for the plans were $88.9 million, $91.7 million and $85.8 million at September 30, 2017, 2016 and 2015, respectively. At September 30, 2017, $14.1 million of the projected benefit obligation is recorded in Other Accruals and Current Liabilities and the remaining $74.8 million is recorded in Other Deferred Credits on the Consolidated Balance Sheets. At September 30, 2016, $9.8 million of the projected benefit obligation was recorded in Other Accruals and Current Liabilities and the remaining $81.9 million was recorded in Other Deferred Credits on the Consolidated Balance Sheets. At September 30, 2015, $4.5 million of the projected benefit obligation was recorded in Other Accruals and Current Liabilities and the remaining $81.3 million was recorded in Other Deferred Credits on the Consolidated Balance Sheets. The weighted average discount rates for these plans were 3.22%, 2.80% and 3.50% as of September 30, 2017, 2016 and 2015, respectively and the weighted average rates of compensation increase for these plans were 7.75%, 7.75% and 7.75% as of September 30, 2017, 2016 and 2015, respectively.
The cumulative amounts recognized in accumulated other comprehensive income (loss), regulatory assets, and regulatory liabilities through fiscal 2017, the changes in such amounts during 2017, as well as the amounts expected to be recognized in net periodic benefit cost in fiscal 2018 are presented in the table below:
 
Retirement
Plan
 
Other
Post-Retirement
Benefits
 
Non-Qualified
Benefit Plans
 
(Thousands)
Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities(1)
 
 
 
 
 
Net Actuarial Loss
$
(203,887
)
 
$
(19,578
)
 
$
(24,332
)
Prior Service (Cost) Credit
(6,133
)
 
3,687

 

Net Amount Recognized
$
(210,020
)
 
$
(15,891
)
 
$
(24,332
)
Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2017(1)
 
 
 
 
 
Decrease (Increase) in Actuarial Loss, excluding amortization(2)
$
57,028

 
$
70,915

 
$
(1,351
)
Change due to Amortization of Actuarial Loss
42,687

 
18,415

 
4,059

Prior Service (Cost) Credit
1,058

 
(429
)
 

Net Change
$
100,773

 
$
88,901

 
$
2,708

Amounts Expected to be Recognized in Net Periodic Benefit Cost in the Next Fiscal Year(1)
 
 
 
 
 
Net Actuarial Loss
$
(37,205
)
 
$
(10,558
)
 
$
(3,549
)
Prior Service (Cost) Credit
(938
)
 
429

 

Net Amount Expected to be Recognized
$
(38,143
)
 
$
(10,129
)
 
$
(3,549
)
 
(1)
Amounts presented are shown before recognizing deferred taxes.
(2)
Amounts presented include the impact of actuarial gains/losses related to return on assets, as well as the Actuarial (Gain) Loss amounts presented in the Change in Benefit Obligation.
In order to adjust the funded status of its pension (tax-qualified and non-qualified) and other post-retirement benefit plans at September 30, 2017, the Company recorded a $163.3 million decrease to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $29.1 million (pre-tax) increase to Accumulated Other Comprehensive Income.
The effect of the discount rate change for the Retirement Plan in 2017 was to decrease the projected benefit obligation of the Retirement Plan by $20.5 million. The mortality improvement projection scale was updated, which decreased the projected benefit obligation of the Retirement Plan in 2017 by $8.3 million. In addition, other actuarial experience decreased the projected benefit obligation for the Retirement Plan in 2017 by $3.6 million. The effect of the discount rate change for the Retirement Plan in 2016 was to increase the projected benefit obligation of the Retirement Plan by $78.5 million. The effect of the mortality assumption change for the Retirement Plan in 2015 was to increase the projected benefit obligation of the Retirement Plan by $24.2 million.
The Company made cash contributions totaling $17.1 million to the Retirement Plan during the year ended September 30, 2017. The Company expects that the annual contribution to the Retirement Plan in 2018 will be in the range of $15.0 million to $40.0 million.
The following Retirement Plan benefit payments, which reflect expected future service, are expected to be paid by the Retirement Plan during the next five years and the five years thereafter: $64.4 million in 2018; $65.0 million in 2019; $65.4 million in 2020; $65.8 million in 2021; $66.2 million in 2022; and $331.1 million in the five years thereafter.
The effect of the discount rate change in 2017 was to decrease the other post-retirement benefit obligation by $6.2 million. The mortality improvement projection scale was updated, which decreased the other post-retirement benefit obligation in 2017 by $5.7 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2017 by $50.3 million primarily attributable to a revision in assumed per-capita claims cost, premiums, retiree contributions and retiree drug subsidy assumptions based on actual experience.
The effect of the discount rate change in 2016 was to increase the other post-retirement benefit obligation by $49.4 million. Other actuarial experience increased the other post-retirement benefit obligation in 2016 by $11.0 million primarily attributable to a revision in assumed per-capita claims cost, premiums, participant contributions and drug subsidy assumptions based on actual experience.
The effect of the discount rate change in 2015 was to decrease the other post-retirement benefit obligation by $14.3 million. Other actuarial experience increased the other post-retirement benefit obligation in 2015 by $12.8 million primarily attributable to the change in mortality assumption.
The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 provides for a prescription drug benefit under Medicare (Medicare Part D), as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D.
The estimated gross other post-retirement benefit payments and gross amount of Medicare Part D prescription drug subsidy receipts are as follows (dollars in thousands):

 
Benefit Payments
 
Subsidy Receipts
2018
$
26,483

 
$
(1,910
)
2019
$
27,456

 
$
(2,074
)
2020
$
28,359

 
$
(2,225
)
2021
$
29,173

 
$
(2,369
)
2022
$
29,757

 
$
(2,515
)
2023 through 2027
$
152,957

 
$
(14,271
)

 
Assumed health care cost trend rates as of September 30 were:
 
2017
 
 
2016
 
 
2015
 
Rate of Medical Cost Increase for Pre Age 65 Participants
5.67
%
(1)
 
5.75
%
(1)
 
6.93
%
(2)
Rate of Medical Cost Increase for Post Age 65 Participants
4.75
%
(1)
 
4.75
%
(1)
 
6.68
%
(2)
Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits
8.45
%
(1)
 
9.00
%
(1)
 
7.17
%
(2)
Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement
4.75
%
(1)
 
4.75
%
(1)
 
6.68
%
(2)
Annual Rate of Increase in the Per Capita Medicare Part D Subsidy
7.33
%
(1)
 
7.20
%
(1)
 
6.65
%
(2)
 
(1)
It was assumed that this rate would gradually decline to 4.5% by 2039.
(2)
It was assumed that this rate would gradually decline to 4.5% by 2028.
The health care cost trend rate assumptions used to calculate the per capita cost of covered medical care benefits have a significant effect on the amounts reported. If the health care cost trend rates were increased by 1% in each year, the other post-retirement benefit obligation as of October 1, 2017 would increase by $57.9 million. This 1% change would also have increased the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 2017 by $3.3 million. If the health care cost trend rates were decreased by 1% in each year, the other post-retirement benefit obligation as of October 1, 2017 would decrease by $48.5 million. This 1% change would also have decreased the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 2017 by $2.7 million.
The Company made cash contributions totaling $3.8 million to its VEBA trusts during the year ended September 30, 2017. In addition, the Company made direct payments of $0.1 million to retirees not covered by the VEBA trusts and 401(h) accounts during the year ended September 30, 2017. The Company expects that the annual contribution to its VEBA trusts in 2018 will be in the range of $2.5 million to $4.0 million.
Investment Valuation
The Retirement Plan assets and other post-retirement benefit assets are valued under the current fair value framework. See Note F — Fair Value Measurements for further discussion regarding the definition and levels of fair value hierarchy established by the authoritative guidance.
The inputs or methodologies used for valuing securities are not necessarily an indication of the risk associated with investing in those securities. Below is a listing of the major categories of plan assets held as of September 30, 2017 and 2016, as well as the associated level within the fair value hierarchy in which the fair value measurements in their entirety fall, based on the lowest level input that is significant to the fair value measurement in its entirety (dollars in thousands):
 
 
Total Fair
 Value Amounts at
September 30, 2017
 
Level 1
 
Level 2
 
Level 3
 
Measured at NAV(7)
Retirement Plan Investments
 
 
 
 
 
 
 
 
 
Domestic Equities(1)
$
290,716

 
$
209,421

 
$

 
$

 
$
81,295

International Equities(2)
123,069

 

 

 

 
123,069

Global Equities(3)
121,008

 

 

 

 
121,008

Domestic Fixed Income(4)
348,501

 
1,664

 
346,837

 

 

International Fixed Income(5)
422

 
422

 

 

 

Global Fixed Income(6)
75,428

 

 

 

 
75,428

Real Estate
3,391

 

 

 
3,391

 

Cash Held in Collective Trust Funds
26,058

 

 

 

 
26,058

Total Retirement Plan Investments
988,593

 
211,507

 
346,837

 
3,391

 
426,858

401(h) Investments
(64,728
)
 
(14,026
)
 
(23,001
)
 
(225
)
 
(27,476
)
Total Retirement Plan Investments (excluding 401(h) Investments)
$
923,865

 
$
197,481

 
$
323,836

 
$
3,166

 
$
399,382

Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash
(13,146
)
 
 
 
 
 
 
 
 
Total Retirement Plan Assets
$
910,719

 
 
 
 
 
 
 
 
 
 
Total Fair 
Value
Amounts at
September 30, 2016
 
Level 1
 
Level 2
 
Level 3
 
Measured at NAV(7)
Retirement Plan Investments
 
 
 
 
 
 
 
 
 
Domestic Equities(1)
$
256,796

 
$
188,253

 
$

 
$

 
$
68,543

International Equities(2)
104,592

 

 

 

 
104,592

Global Equities(3)
120,025

 

 

 

 
120,025

Domestic Fixed Income(4)
342,442

 
1,647

 
340,795

 

 

International Fixed Income(5)
744

 
407

 
337

 

 

Global Fixed Income(6)
81,146

 

 

 

 
81,146

Real Estate
2,970

 

 

 
2,970

 

Cash Held in Collective Trust Funds
24,812

 

 

 

 
24,812

Total Retirement Plan Investments
933,527

 
190,307

 
341,132

 
2,970

 
399,118

401(h) Investments
(58,707
)
 
(12,025
)
 
(21,555
)
 
(188
)
 
(24,939
)
Total Retirement Plan Investments (excluding 401(h) Investments)
$
874,820

 
$
178,282

 
$
319,577

 
$
2,782

 
$
374,179

Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash
(5,045
)
 
 
 
 
 
 
 
 
Total Retirement Plan Assets
$
869,775

 
 
 
 
 
 
 
 
 
(1)
Domestic Equities include mostly collective trust funds, common stock, and exchange traded funds.
(2)
International Equities are comprised of collective trust funds.
(3)
Global Equities are comprised of collective trust funds.
(4)
Domestic Fixed Income securities include mostly collective trust funds, corporate/government bonds and mortgages, and exchange traded funds.
(5)
International Fixed Income securities are comprised mostly of an exchange traded fund.
(6)
Global Fixed Income securities are comprised of a collective trust fund.
(7)
Reflects the adoption of the new authoritative guidance related to investments measured at the net asset value (NAV) practical expedient.

 
Total Fair
 Value
Amounts at
September 30, 2017
 
Level 1
 
Level 2
 
Level 3
 
Measured at NAV(1)
Other Post-Retirement Benefit Assets held in VEBA Trusts
 
 
 
 
 
 
 
 
 
Collective Trust Funds — Domestic Equities
$
130,864

 
$

 
$

 
$

 
$
130,864

Collective Trust Funds — International Equities
52,063

 

 

 

 
52,063

Exchange Traded Funds — Fixed Income
256,099

 
256,099

 

 

 

Cash Held in Collective Trust Funds
9,569

 

 

 

 
9,569

Total VEBA Trust Investments
448,595

 
256,099

 

 

 
192,496

401(h) Investments
64,728

 
14,026

 
23,001

 
225

 
27,476

Total Investments (including 401(h) Investments)
$
513,323

 
$
270,125

 
$
23,001

 
$
225

 
$
219,972

Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative)
694

 
 
 
 
 
 
 
 
Total Other Post-Retirement Benefit Assets
$
514,017

 
 
 
 
 
 
 
 
 
 
Total Fair
 Value
Amounts at
September 30, 2016
 
Level 1
 
Level 2
 
Level 3
 
Measured at NAV(1)
Other Post-Retirement Benefit Assets held in VEBA Trusts
 
 
 
 
 
 
 
 
 
Collective Trust Funds — Domestic Equities
$
139,617

 
$

 
$

 
$

 
$
139,617

Collective Trust Funds — International Equities
51,488

 

 

 

 
51,488

Exchange Traded Funds — Fixed Income
230,761

 
230,761

 

 

 

Cash Held in Collective Trust Funds
13,176

 

 

 

 
13,176

Total VEBA Trust Investments
435,042

 
230,761

 

 

 
204,281

401(h) Investments
58,707

 
12,025

 
21,555

 
188

 
24,939

Total Investments (including 401(h) Investments)
$
493,749

 
$
242,786

 
$
21,555

 
$
188

 
$
229,220

Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative)
571

 
 
 
 
 
 
 
 
Total Other Post-Retirement Benefit Assets
$
494,320

 
 
 
 
 
 
 
 

 
(1)
Reflects the adoption of the new authoritative guidance related to investments measured at the net asset value (NAV) practical expedient.
The fair values disclosed in the above tables may not be indicative of net realizable value or reflective of future fair values. Furthermore, although the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.
The following tables provide a reconciliation of the beginning and ending balances of the Retirement Plan and other post-retirement benefit assets measured at fair value on a recurring basis where the determination of fair value includes significant unobservable inputs (Level 3). For the years ended September 30, 2017 and September 30, 2016, there were no transfers from Level 1 to Level 2. In addition, as shown in the following tables, there were no transfers in or out of Level 3.
 
 
Retirement Plan Level 3 Assets
(Thousands)
 
 
Hedge
Funds
 
Real
Estate
 
Excluding
401(h)
Investments
 
Total
 
 
 
Balance at September 30, 2015
$
26,490

 
$
4,724

 
$
(1,885
)
 
$
29,329

 
Realized Gains/(Losses)
5,878

 

 
(354
)
 
5,524

 
Unrealized Gains/(Losses)
(5,445
)
 
(404
)
 
344

 
(5,505
)
 
Sales
(26,923
)
 
(1,350
)
 
1,707

 
(26,566
)
 
Balance at September 30, 2016

 
2,970


(188
)

2,782

 
Unrealized Gains/(Losses)

 
421

 
(37
)
 
384

 
Balance at September 30, 2017
$

 
$
3,391

 
$
(225
)
 
$
3,166


 
 
 
Other Post-Retirement Benefit Level 3 Assets
(Thousands)
 
 
401(h)
Investments
 
 
Balance at September 30, 2015
 
$
1,885

Realized Gains/(Losses)
 
354

Unrealized Gains/(Losses)
 
(344
)
Sales
 
(1,707
)
Balance at September 30, 2016
 
188

Unrealized Gains/(Losses)
 
37

Balance at September 30, 2017
 
$
225


The Company’s assumption regarding the expected long-term rate of return on plan assets is 7.00% (Retirement Plan) and 6.25% (other post-retirement benefits), effective for fiscal 2018. The return assumption reflects the anticipated long-term rate of return on the plan’s current and future assets. The Company utilizes projected capital market conditions and the plan’s target asset class and investment manager allocations to set the assumption regarding the expected return on plan assets.
The long-term investment objective of the Retirement Plan trust, the VEBA trusts and the 401(h) accounts is to achieve the target total return in accordance with the Company’s risk tolerance. Assets are diversified utilizing a mix of equities, fixed income and other securities (including real estate). The target allocation for the Retirement Plan and the VEBA trusts (including 401(h) accounts) is 40-60% equity securities, 40-60% fixed income securities and 0-15% other. Risk tolerance is established through consideration of plan liabilities, plan funded status and corporate financial condition. The assets of the Retirement Plan trusts, VEBA trusts and the 401(h) accounts have no significant concentrations of risk in any one country (other than the United States), industry or entity.
Investment managers are retained to manage separate pools of assets. Comparative market and peer group performance of individual managers and the total fund are monitored on a regular basis, and reviewed by the Company’s Retirement Committee on at least a quarterly basis.
Beginning in fiscal 2018, the Company refined the method used to determine the service and interest cost components of net periodic benefit cost. Using the refined method, known as the spot rate approach, the Company will use individual spot rates along the yield curve that correspond to the timing of each benefit payment to determine the discount rate. The individual spot rates along the yield curve will continue to be determined by an above mean methodology in that the coupon interest rates that are in the lower 50th percentile will be excluded based on the assumption that the Company would not utilize more expensive (i.e. lower yield) instruments to settle its liabilities. The impact on the benefit obligation, as of September 30, 2017, is immaterial. This change will provide a more precise measurement of service and interest costs by improving the correlation between projected cash outflows and corresponding spot rates on the yield curve. Compared to the previous method, the spot rate approach will decrease the service and interest components of net periodic benefit costs in fiscal 2018. The Company will account for this change prospectively as a change in accounting estimate.
Commitments And Contingencies
Commitments And Contingencies
Commitments and Contingencies
Environmental Matters
The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory requirements.
It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. At September 30, 2017, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $3.1 million. This estimated liability has been recorded in Other Deferred Credits on the Consolidated Balance Sheet at September 30, 2017. The Company expects to recover its environmental clean-up costs through rate recovery over a period of approximately 4 years. The Company is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental laws and regulations, new information or other factors could could have an adverse financial impact on the Company.
Northern Access 2016 Project
On February 3, 2017, Supply Corporation and Empire received FERC approval of the Northern Access 2016 project described herein. On April 7, 2017, the NYDEC issued a Notice of Denial of the federal Clean Water Act Section 401 Water Quality Certification and other state stream and wetland permits for the New York portion of the project (the Water Quality Certification for the Pennsylvania portion of the project was received on January 27, 2017). On April 21, 2017, Supply Corporation and Empire filed a Petition for Review in the United States Court of Appeals for the Second Circuit of the NYDEC's Notice of Denial with respect to National Fuel's application for the Water Quality Certification, and on May 11, 2017, the Company commenced legal action in New York State Supreme Court challenging the NYDEC's actions with regard to various state permits. The Company also has pending with FERC a proceeding asserting, among other things, that the NYDEC exceeded the reasonable time frame to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification. In light of these pending legal actions, the Company has not yet determined a target in-service date. As a result of the decision of the NYDEC, Supply Corporation and Empire evaluated the capitalized project costs for impairment as of September 30, 2017 and determined that an impairment charge was not required. The evaluation considered probability weighted scenarios of undiscounted future net cash flows, including a scenario assuming successful resolution with the NYDEC and construction of the pipeline, as well as a scenario where the project does not proceed. Further developments or indicators of an unfavorable resolution could result in the impairment of a significant portion of the project costs, which totaled $75.8 million at September 30, 2017. The project costs are included within Property, Plant and Equipment and Deferred Charges on the Consolidated Balance Sheet.
Other
The Company, in its Utility segment, Energy Marketing segment, and Exploration and Production segment, has entered into contractual commitments in the ordinary course of business, including commitments to purchase gas, transportation, and storage service to meet customer gas supply needs. The future gas purchase, transportation and storage contract commitments during the next five years and thereafter are as follows: $262.4 million in 2018, $84.6 million in 2019, $77.9 million in 2020, $70.9 million in 2021, $61.7 million in 2022 and $504.9 million thereafter. Gas prices within the gas purchase contracts are variable based on NYMEX prices adjusted for basis. In the Utility segment, these costs are subject to state commission review, and are being recovered in customer rates. Management believes that, to the extent any stranded pipeline costs are generated by the unbundling of services in the Utility segment’s service territory, such costs will be recoverable from customers.
The Company has entered into leases for the use of compressors, drilling rigs, buildings and other items. These leases are accounted for as operating leases. The future lease commitments during the next five years and thereafter are as follows: $10.8 million in 2018, $4.6 million in 2019, $3.7 million in 2020, $2.2 million in 2021, $1.5 million in 2022 and $1.9 million thereafter.
The Company, in its Pipeline and Storage segment, Gathering segment and Utility segment, has entered into several contractual commitments associated with various pipeline, compressor and gathering system modernization and expansion projects. As of September 30, 2017, the future contractual commitments related to the system modernization and expansion projects are $61.7 million in 2018, $0.7 million in 2019, $0.2 million in 2020, $0.3 million in 2021, $0.3 million in 2022 and $1.1 million thereafter.
The Company, in its Exploration and Production segment, has entered into contractual obligations associated with hydraulic fracturing and fuel. The future contractual commitments are $79.5 million in 2018, $98.0 million in 2019 and $17.1 million in 2020. There are no contractual commitments extending beyond 2020.
The Company is involved in other litigation arising in the normal course of business. In addition to the regulatory matters discussed in Note C — Regulatory Matters, the Company is involved in other regulatory matters arising in the normal course of business. These other litigation and regulatory matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations and other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these other matters arising in the normal course of business could have a material effect on earnings and cash flows in the period in which they are resolved, an estimate of the possible loss or range of loss, if any, cannot be made at this time.
Business Segment Information
Business Segment Information
Business Segment Information
The Company reports financial results for five segments: Exploration and Production, Pipeline and Storage, Gathering, Utility and Energy Marketing. The division of the Company’s operations into reportable segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors.
The Exploration and Production segment, through Seneca, is engaged in exploration for and development of natural gas and oil reserves in California and the Appalachian region of the United States.
The Pipeline and Storage segment operations are regulated by the FERC for both Supply Corporation and Empire. Supply Corporation transports and stores natural gas for utilities (including Distribution Corporation), natural gas marketers (including NFR), exploration and production companies (including Seneca) and pipeline companies in the northeastern United States markets. Empire transports and stores natural gas for major industrial companies, utilities (including Distribution Corporation) and power producers in New York State. Empire also transports natural gas for natural gas marketers along with exploration and production companies from natural gas producing areas in Pennsylvania to markets in New York and to interstate pipeline delivery points for additional markets in the northeastern United States and Canada.
The Gathering segment is comprised of Midstream Corporation’s operations. Midstream Corporation builds, owns and operates natural gas processing and pipeline gathering facilities in the Appalachian region and currently provides gathering services to Seneca.
The Utility segment operations are regulated by the NYPSC and the PaPUC and are carried out by Distribution Corporation. Distribution Corporation sells natural gas to retail customers and provides natural gas transportation services in western New York and northwestern Pennsylvania.
The Energy Marketing segment is comprised of NFR’s operations. NFR markets natural gas to industrial, wholesale, commercial, public authority and residential customers primarily in western and central New York and northwestern Pennsylvania, offering competitively priced natural gas for its customers. 
The data presented in the tables below reflects financial information for the segments and reconciliations to consolidated amounts. The accounting policies of the segments are the same as those described in Note A — Summary of Significant Accounting Policies. Sales of products or services between segments are billed at regulated rates or at market rates, as applicable. The Company evaluates segment performance based on income before discontinued operations, extraordinary items and cumulative effects of changes in accounting (when applicable). When these items are not applicable, the Company evaluates performance based on net income. 
 
Year Ended September 30, 2017
 
Exploration
and
Production
 
Pipeline
and
Storage
 
Gathering
 
Utility
 
Energy
Marketing
 
Total
Reportable
Segments
 
All
Other
 
Corporate
and
Intersegment
Eliminations
 
Total
Consolidated
 
(Thousands)
Revenue from External Customers(1)
$
614,599

 
$
206,615

 
$
115

 
$
626,899

 
$
128,586

 
$
1,576,814

 
$
2,173

 
$
894

 
$
1,579,881

Intersegment Revenues
$

 
$
87,810

 
$
107,566

 
$
13,072

 
$
794

 
$
209,242

 
$

 
$
(209,242
)
 
$

Interest Income
$
707

 
$
1,467

 
$
994

 
$
1,051

 
$
571

 
$
4,790

 
$
213

 
$
(890
)
 
$
4,113

Interest Expense
$
53,702

 
$
33,717

 
$
9,142

 
$
28,492

 
$
47

 
$
125,100

 
$

 
$
(5,263
)
 
$
119,837

Depreciation, Depletion and Amortization
$
112,565

 
$
41,196

 
$
16,162

 
$
52,582

 
$
279

 
$
222,784

 
$
661

 
$
750

 
$
224,195

Income Tax Expense (Benefit)
$
66,093

 
$
40,947

 
$
29,694

 
$
24,894

 
$
891

 
$
162,519

 
$
(247
)
 
$
(1,590
)
 
$
160,682

Segment Profit: Net Income (Loss)
$
129,326

 
$
68,446

 
$
40,377

 
$
46,935

 
$
1,509

 
$
286,593

 
$
(342
)
 
$
(2,769
)
 
$
283,482

Expenditures for Additions to Long-Lived Assets
$
253,057

 
$
95,336

 
$
32,645

 
$
80,867

 
$
36

 
$
461,941

 
$
39

 
$
137

 
$
462,117

 
At September 30, 2017
 
(Thousands)
Segment Assets
$
1,407,152

 
$
1,929,788

 
$
580,051

 
$
2,013,123

 
$
60,937

 
$
5,991,051

 
$
76,861

 
$
35,408

 
$
6,103,320

 
 
Year Ended September 30, 2016
 
Exploration
and
Production
 
Pipeline
and
Storage
 
Gathering
 
Utility
 
Energy
Marketing
 
Total
Reportable
Segments
 
All
Other
 
Corporate
and
Intersegment
Elimination
 
Total
Consolidated
 
(Thousands)
Revenue from External Customers(1)
$
607,113

 
$
215,674

 
$
374

 
$
531,024

 
$
93,578

 
$
1,447,763

 
$
3,753

 
$
900

 
$
1,452,416

Intersegment Revenues
$

 
$
90,755

 
$
89,073

 
$
13,123

 
$
884

 
$
193,835

 
$

 
$
(193,835
)
 
$

Interest Income
$
858

 
$
770

 
$
297

 
$
1,737

 
$
422

 
$
4,084

 
$
117

 
$
34

 
$
4,235

Interest Expense
$
55,434

 
$
33,327

 
$
8,872

 
$
27,582

 
$
49

 
$
125,264

 
$

 
$
(4,220
)
 
$
121,044

Depreciation, Depletion and Amortization
$
139,963

 
$
43,273

 
$
15,282

 
$
48,618

 
$
278

 
$
247,414

 
$
1,260

 
$
743

 
$
249,417

Income Tax Expense (Benefit)
$
(334,029
)
 
$
50,241

 
$
24,334

 
$
25,602

 
$
2,460

 
$
(231,392
)
 
$
561

 
$
(1,718
)
 
$
(232,549
)
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties
$
948,307

 
$

 
$

 
$

 
$

 
$
948,307

 
$

 
$

 
$
948,307

Segment Profit: Net Income (Loss)
$
(452,842
)
 
$
76,610

 
$
30,499

 
$
50,960

 
$
4,348

 
$
(290,425
)
 
$
778

 
$
(1,311
)
 
$
(290,958
)
Expenditures for Additions to Long-Lived Assets
$
256,104

 
$
114,250

 
$
54,293

 
$
98,007

 
$
34

 
$
522,688

 
$
37

 
$
326

 
$
523,051

 
At September 30, 2016
 
(Thousands)
Segment Assets
$
1,323,081

 
$
1,680,734

 
$
534,259

 
$
2,021,514

 
$
63,392

 
$
5,622,980

 
$
77,138

 
$
(63,731
)
 
$
5,636,387

 
 
Year Ended September 30, 2015
 
Exploration
and
Production
 
Pipeline
and
Storage
 
Gathering
 
Utility
 
Energy
Marketing
 
Total
Reportable
Segments
 
All
Other
 
Corporate
and
Intersegment
Eliminations
 
Total
Consolidated
 
(Thousands)
Revenue from External Customers(1)
$
693,441

 
$
203,089

 
$
497

 
$
700,761

 
$
159,857

 
$
1,757,645

 
$
2,352

 
$
916

 
$
1,760,913

Intersegment Revenues
$

 
$
88,251

 
$
76,709

 
$
15,506

 
$
849

 
$
181,315

 
$

 
$
(181,315
)
 
$

Interest Income
$
2,554

 
$
474

 
$
140

 
$
2,220

 
$
195

 
$
5,583

 
$
66

 
$
(1,727
)
 
$
3,922

Interest Expense
$
46,726

 
$
27,658

 
$
1,627

 
$
28,176

 
$
27

 
$
104,214

 
$

 
$
(4,743
)
 
$
99,471

Depreciation, Depletion and Amortization
$
239,818

 
$
38,178

 
$
10,829

 
$
45,616

 
$
209

 
$
334,650

 
$
832

 
$
676

 
$
336,158

Income Tax Expense (Benefit)
$
(428,217
)
 
$
48,113

 
$
24,721

 
$
33,143

 
$
4,547

 
$
(317,693
)
 
$
13

 
$
(1,456
)
 
$
(319,136
)
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties
$
1,126,257

 
$

 
$

 
$

 
$

 
$
1,126,257

 
$

 
$

 
$
1,126,257

Segment Profit: Net Income (Loss)
$
(556,974
)
 
$
80,354

 
$
31,849

 
$
63,271

 
$
7,766

 
$
(373,734
)
 
$
(2
)
 
$
(5,691
)
 
$
(379,427
)
Expenditures for Additions to Long-Lived Assets
$
557,313

 
$
230,192

 
$
118,166

 
$
94,371

 
$
128

 
$
1,000,170

 
$

 
$
339

 
$
1,000,509

 
At September 30, 2015
 
(Thousands)
Segment Assets
$
2,439,801

 
$
1,590,524

 
$
444,358

 
$
1,934,731

 
$
90,676

 
$
6,500,090

 
$
77,350

 
$
(12,501
)
 
$
6,564,939

 
(1)
All Revenue from External Customers originated in the United States.
Geographic Information
At September 30
 
2017
 
2016
 
2015
 
(Thousands)
Long-Lived Assets:
 
 
 
 
 
United States
$
5,285,040

 
$
5,223,356

 
$
6,189,138

Quarterly Financial Data
Quarterly Financial Data
Quarterly Financial Data (unaudited)
In the opinion of management, the following quarterly information includes all adjustments necessary for a fair statement of the results of operations for such periods. Per common share amounts are calculated using the weighted average number of shares outstanding during each quarter. The total of all quarters may differ from the per common share amounts shown on the Consolidated Statements of Income. Those per common share amounts are based on the weighted average number of shares outstanding for the entire fiscal year. Because of the seasonal nature of the Company’s heating business, there are substantial variations in operations reported on a quarterly basis. 
 
Quarter Ended
Operating
Revenues
 
Operating
Income (Loss)
 
Net 
Income (Loss)
Available for
Common Stock
 
Earnings (Loss) per
Common Share
 
 
Basic
 
Diluted
 
 
(Thousands, except per common share amounts)
 
2017
 
 
 
 
 
 
 
 
 
 
9/30/2017
$
286,937

 
$
87,395

 
$
45,577

 
$
0.53

 
$
0.53

 
6/30/2017
$
348,369

 
$
123,354

 
$
59,714

 
$
0.70

 
$
0.69

 
3/31/2017
$
522,075

 
$
169,957

 
$
89,283

 
$
1.05

 
$
1.04

 
12/31/2016
$
422,500

 
$
172,139

 
$
88,908

 
$
1.04

 
$
1.04

 
2016
 
 
 
 
 
 
 
 
 
 
9/30/2016
$
292,472

 
$
81,244

 
$
37,553

(1)
$
0.44

 
$
0.44

 
6/30/2016
$
335,617

 
$
45,162

 
$
8,286

(2)
$
0.10

 
$
0.10

 
3/31/2016
$
449,132

 
$
(237,000
)
 
$
(147,688
)
(3)
$
(1.74
)
 
$
(1.74
)
 
12/31/2015
$
375,195

 
$
(305,924
)
 
$
(189,109
)
(4)
$
(2.23
)
 
$
(2.23
)
 
(1)
Includes a non-cash $32.7 million impairment charge ($19.0 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
(2)
Includes a non-cash $82.7 million impairment charge ($47.9 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
(3)
Includes a non-cash $397.4 million impairment charge ($230.5 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
(4)
Includes a non-cash $435.5 million impairment charge ($252.6 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
Supplementary Information For Oil And Gas Producing Activities
Supplementary Information for Oil and Gas Producing Activities (unaudited, except for Capitalized Costs Relating to Oil and Gas Producing Activities)
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
 
2017
 
2016
 
(Thousands)
Proved Properties(1)
$
4,832,301

 
$
4,554,929

Unproved Properties
80,932

 
135,285

 
4,913,233

 
4,690,214

Less — Accumulated Depreciation, Depletion and Amortization
3,765,710

 
3,657,239

 
$
1,147,523

 
$
1,032,975

 
(1)
Includes asset retirement costs of $54.4 million and $63.6 million at September 30, 2017 and 2016, 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 2018. Following is a summary of costs excluded from amortization at September 30, 2017:
 
Total as of
September 30,
2017
 
Year Costs Incurred
 
 
2017
 
2016
 
2015
 
Prior
 
(Thousands)
Acquisition Costs
$
55,193

 
$

 
$

 
$

 
$
55,193

Development Costs
11,879

 
4,388

 
6,707

 
416

 
368

Exploration Costs
13,388

 
2,376

 
7,593

 
3,419

 

Capitalized Interest
472

 
235

 
149

 
88

 

 
$
80,932

 
$
6,999

 
$
14,449

 
$
3,923

 
$
55,561


Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
 
Year Ended September 30
 
2017
 
2016
 
2015
 
(Thousands)
United States
 
Property Acquisition Costs:
 
 
 
 
 
Proved
$
8,908

 
$
1,342

 
$
1,767

Unproved
262

 
2,165

 
19,998

Exploration Costs(1)
40,975

 
27,561

 
53,222

Development Costs(2)
200,639

 
219,386

 
454,605

Asset Retirement Costs
(9,175
)
 
(49,653
)
 
37,595

 
$
241,609

 
$
200,801

 
$
567,187

 
(1)
Amounts for 2017, 2016 and 2015 include capitalized interest of $0.3 million, $0.3 million and $0.4 million, respectively.
(2)
Amounts for 2017, 2016 and 2015 include capitalized interest of $0.2 million, $0.2 million and $0.5 million, respectively.
For the years ended September 30, 2017, 2016 and 2015, the Company spent $101.1 million, $92.8 million and $161.8 million, respectively, developing proved undeveloped reserves.
Results of Operations for Producing Activities
 
Year Ended September 30
 
2017
 
2016
 
2015
United States
(Thousands, except per Mcfe amounts)
Operating Revenues:
 
 
 
 
 
Natural Gas (includes transfers to operations of $2,357, $1,765 and $1,946, respectively)(1)
$
399,975

 
$
282,619

 
$
350,673

Oil, Condensate and Other Liquids
126,517

 
103,533

 
156,048

Total Operating Revenues(2)
526,492

 
386,152

 
506,721

Production/Lifting Costs
165,991

 
153,914

 
167,800

Franchise/Ad Valorem Taxes
15,372

 
13,794

 
20,167

Purchased Emission Allowance Expense
1,391

 
700

 
3,089

Accretion Expense
4,896

 
6,663

 
6,186

Depreciation, Depletion and Amortization ($0.63, $0.85 and $1.49 per Mcfe of production, respectively)
108,471

 
136,579

 
234,480

Impairment of Oil and Gas Producing Properties

 
948,307

 
1,126,257

Income Tax Expense (Benefit)
86,657

 
(368,940
)
 
(444,393
)
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)
$
143,714

 
$
(504,865
)
 
$
(606,865
)
 
(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, 2017 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, 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

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

Proved Developed Reserves:
 
 
 
 


September 30, 2014
1,119,901

  
57,907

 
1,177,808

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

Proved Undeveloped Reserves:
 
 
 
 


September 30, 2014
504,161

  
915

 
505,076

September 30, 2015
825,284

  

 
825,284

September 30, 2016
541,959

  

 
541,959

September 30, 2017
610,018

  

 
610,018

 
(1)
Extensions and discoveries include 598 Bcf (during 2015), 179 Bcf (during 2016) and 181 Bcf (during 2017), of Marcellus Shale gas in the Appalachian region.
(2)
Production includes 130,291 MMcf (during 2015), 135,598 MMcf (during 2016) and 145,452 MMcf (during 2017), 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, 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

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

Proved Developed Reserves:
 
 
 
 

September 30, 2014
253

 
37,002

 
37,255

September 30, 2015
220

 
33,150

 
33,370

September 30, 2016
73

 
28,698

 
28,771

September 30, 2017
28

 
29,771

 
29,799

Proved Undeveloped Reserves:
 
 
 
 


September 30, 2014

 
1,222

 
1,222

September 30, 2015

 
352

 
352

September 30, 2016

 
238

 
238

September 30, 2017

 
408

 
408


The Company’s proved undeveloped (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 Company’s PUD reserves decreased from 827 Bcfe at September 30, 2015 to 543 Bcfe at September 30, 2016. PUD reserves in the Marcellus Shale decreased from 825 Bcfe at September 30, 2015 to 542 Bcfe at September 30, 2016. The Company’s total PUD reserves were 29% of total proved reserves at September 30, 2016, down from 35% of total proved reserves at September 30, 2015.
The increase in PUD reserves in 2017 of 69 Bcfe is 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. The PUD reserves removed were all in the Marcellus Shale and were due to a couple of factors. PUD reserves of 36 Bcfe associated with a few wells 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. This will now take longer than the five year time horizon from original booking. PUD reserves of 18 Bcfe were removed due to a change in plans this year and its impact on a few wells. As part of Seneca’s transition toward a Utica focused development program in the Western Development Area, certain Marcellus wells have been replaced with Utica wells in our development plan.
The decrease in PUD reserves in 2016 of 284 Bcfe was a result of 102 Bcfe in new PUD reserve additions (102 Bcfe from the Marcellus Shale), offset by sales of 166 Bcfe associated with a joint development agreement (JDA) that Seneca entered into in December 2015, 14 Bcfe in downward revisions to remaining PUD reserves, offset by 110 Bcfe in PUD conversions to developed reserves and 96 Bcfe in PUD reserves removed. The PUD reserves removed were primarily in the Marcellus Shale (74 Bcfe) and were due to several factors including schedule changes, lower performance expectations and lower natural gas pricing. Geneseo Shale PUD reserves of 23 Bcfe were removed solely due to lower gas pricing as they were uneconomic at trailing twelve month pricing.
The Company invested $101 million during the year ended September 30, 2017 to convert 147 Bcfe (159 Bcfe before revisions) of Marcellus 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 wells that were recorded at September 30, 2016. The vast majority of these wells were in the Appalachian region.
The Company invested $93 million (includes $36 million of drilling carry costs for a JDA partner that were later reimbursed) during the year ended September 30, 2016 to convert 92 Bcfe (110 Bcfe before revisions) of PUD reserves to developed reserves. This represents 11% of the net PUD reserves recorded at September 30, 2015. In 2016, the majority of Seneca's planned PUD reserves development was funded by a JDA partner, which reduced Seneca's working interest, as discussed in Note A — Summary of Significant Accounting Policies under the heading “Property, Plant and Equipment.” In fiscal 2016, the Company developed 31 (or 28%) of its gross Marcellus Shale wells that were recorded at September 30, 2015. The majority of these wells were included in the JDA.  Including the impact of JDA sales, the Company developed 207 Bcfe (or 25%) of its net PUD reserves recorded at September 30, 2015. In addition, as stated above, the sales associated with the JDA further decreased PUD reserves. 
As part of Seneca’s JDA in the Marcellus Shale, Seneca anticipates it will sell approximately 60 Bcfe of its working interest PUD reserves in 2018 to its JDA partner as it develops the last group of wells included in the JDA.
In 2018, the Company estimates that it will invest approximately $186 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 39% of its beginning year PUD reserves in fiscal 2013, 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 and 27% of its beginning year PUD reserves in fiscal 2017.
At September 30, 2017, 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
 
2017
 
2016
 
2015
 
(Thousands)
United States
 
 
 
 
 
Future Cash Inflows
$
6,144,317

 
$
3,768,463

 
$
6,916,775

Less:
 
 
 
 
 
Future Production Costs
2,378,262

 
1,994,916

 
2,854,142

Future Development Costs
411,578

 
375,152

 
761,922

Future Income Tax Expense at Applicable Statutory Rate
1,160,469

 
303,397

 
1,117,433

Future Net Cash Flows
2,194,008

 
1,094,998

 
2,183,278

Less:
 
 
 
 
 
10% Annual Discount for Estimated Timing of Cash Flows
1,080,962

 
452,470

 
860,244

Standardized Measure of Discounted Future Net Cash Flows
$
1,113,046

 
$
642,528

 
$
1,323,034


The principal sources of change in the standardized measure of discounted future net cash flows were as follows:
 
Year Ended September 30
 
2017
 
2016
 
2015
 
(Thousands)
United States
 
 
 
 
 
Standardized Measure of Discounted Future
 
 
 
 
 
Net Cash Flows at Beginning of Year
$
642,528

 
$
1,323,034

 
$
2,066,878

Sales, Net of Production Costs
(345,075
)
 
(218,444
)
 
(318,753
)
Net Changes in Prices, Net of Production Costs
828,187

 
(1,066,593
)
 
(1,752,843
)
Extensions and Discoveries
170,500

 
47,742

 
266,159

Changes in Estimated Future Development Costs
8,816

 
143,752

 
164,510

Sales of Minerals in Place
(9,849
)
 
(95,849
)
 
(1
)
Previously Estimated Development Costs Incurred
101,134

 
92,840

 
161,833

Net Change in Income Taxes at Applicable Statutory Rate
(393,353
)
 
387,739

 
545,442

Revisions of Previous Quantity Estimates
39,078

 
6,202

 
(16,573
)
Accretion of Discount and Other
71,080

 
22,105

 
206,382

Standardized Measure of Discounted Future Net Cash Flows at End of Year
$
1,113,046

 
$
642,528

 
$
1,323,034

Valuation And Qualifying Accounts
Valuation And Qualifying Accounts
Schedule II — Valuation and Qualifying Accounts
 
Description
Balance at Beginning of Period
 
Additions Charged to Costs and Expenses
 
Additions Charged to Other Accounts(1)
 
Deductions (2)
 
Balance at End of Period
Year Ended September 30, 2017
 
 
 
 
 
 
 
 
 
Allowance for Uncollectible Accounts
$
21,109

 
$
6,301

 
$
1,774

 
$
6,658

 
$
22,526

Year Ended September 30, 2016
 
 
 
 
 
 
 
 
 
Allowance for Uncollectible Accounts
$
29,029

 
$
6,819

 
$
1,521

 
$
16,260

 
$
21,109

Year Ended September 30, 2015
 
 
 
 
 
 
 
 
 
Allowance for Uncollectible Accounts
$
31,811

 
$
9,316

 
$
2,585

 
$
14,683

 
$
29,029

 
(1)
Represents the discount on accounts receivable purchased in accordance with the Utility segment’s 2005 New York rate agreement.
(2)
Amounts represent net accounts receivable written-off.
Summary Of Significant Accounting Policies (Policy)
Principles of Consolidation
The Company consolidates all entities in which it has a controlling financial interest. All significant intercompany balances and transactions are eliminated. The Company uses proportionate consolidation when accounting for drilling arrangements related to oil and gas producing properties accounted for under the full cost method of accounting.
The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Reclassification
Certain prior year amounts have been reclassified to conform with current year presentation.
Regulation
The Company is subject to regulation by certain state and federal authorities. The Company has accounting policies which conform to GAAP, as applied to regulated enterprises, and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. Reference is made to Note C — Regulatory Matters for further discussion.
Revenue Recognition
The Company’s Exploration and Production segment records revenue based on entitlement, which means that revenue is recorded based on the actual amount of gas or oil that is delivered to a pipeline and the Company’s ownership interest in the producing well. If a production imbalance occurs between what was supposed to be delivered to a pipeline and what was actually produced and delivered, the Company accrues the difference as an imbalance.
The Company’s Pipeline and Storage segment records revenue for natural gas transportation and storage services. Revenue from reservation charges on firm contracted capacity is recognized through equal monthly charges over the contract period regardless of the amount of gas that is transported or stored. Commodity charges on firm contracted capacity and interruptible contracts are recognized as revenue when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage field. The point of delivery into the pipeline or injection or withdrawal from storage is the point at which ownership and risk of loss transfers to the buyer of such transportation and storage services.
In the Company’s Gathering segment, revenue is recorded at the point at which gathered volumes are delivered into interstate pipelines.
The Company’s Utility segment records revenue for gas sales and transportation in the period that gas is delivered to customers. This includes the recording of receivables for gas delivered but not yet billed to customers based on the Company's estimate of the amount of gas delivered between the last meter reading date and the end of the accounting period. Such receivables are a component of Unbilled Revenue on the Consolidated Balance Sheets.
The Company’s Energy Marketing segment records revenue for gas sales in the period that gas is delivered to customers. This includes the recording of receivables for gas delivered but not yet billed to customers based on the Company's estimate of the amount of gas delivered between the last meter reading date and the end of the accounting period. Such receivables are a component of Unbilled Revenue on the Consolidated Balance Sheets.
Allowance for Uncollectible Accounts
The allowance for uncollectible accounts is the Company’s best estimate of the amount of probable credit losses in the existing accounts receivable. The allowance is determined based on historical experience, the age and other specific information about customer accounts. Account balances are charged off against the allowance twelve months after the account is final billed or when it is anticipated that the receivable will not be recovered.
Regulatory Mechanisms
The Company’s rate schedules in the Utility segment contain clauses that permit adjustment of revenues to reflect price changes from the cost of purchased gas included in base rates. Differences between amounts currently recoverable and actual adjustment clause revenues, as well as other price changes and pipeline and storage company refunds not yet includable in adjustment clause rates, are deferred and accounted for as either unrecovered purchased gas costs or amounts payable to customers. Such amounts are generally recovered from (or passed back to) customers during the following fiscal year.
Estimated refund liabilities to ratepayers represent management’s current estimate of such refunds. Reference is made to Note C — Regulatory Matters for further discussion.
The impact of weather on revenues in the Utility segment’s New York rate jurisdiction is tempered by a WNC, which covers the eight-month period from October through May. The WNC is designed to adjust the rates of retail customers to reflect the impact of deviations from normal weather. Weather that is warmer than normal results in a surcharge being added to customers’ current bills, while weather that is colder than normal results in a refund being credited to customers’ current bills. Since the Utility segment’s Pennsylvania rate jurisdiction does not have a WNC, weather variations have a direct impact on the Pennsylvania rate jurisdiction’s revenues.
The impact of weather normalized usage per customer account in the Utility segment’s New York rate jurisdiction is tempered by a revenue decoupling mechanism. The effect of the revenue decoupling mechanism is to render the Company financially indifferent to throughput decreases resulting from conservation. Weather normalized usage per account that exceeds the average weather normalized usage per customer account results in a refund being credited to customers’ bills. Weather normalized usage per account that is below the average weather normalized usage per account results in a surcharge being added to customers’ bills. The surcharge or credit is calculated over a twelve-month period ending December 31st, and applied to customer bills annually, beginning March 1st.
In the Pipeline and Storage segment, the allowed rates that Supply Corporation and Empire bill their customers are based on a straight fixed-variable rate design, which allows recovery of all fixed costs, including return on equity and income taxes, through fixed monthly reservation charges. Because of this rate design, changes in throughput due to weather variations do not have a significant impact on the revenues of Supply Corporation or Empire.
Property, Plant and Equipment
In the Company’s Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. For further discussion of capitalized costs, refer to Note M — Supplementary Information for Oil and Gas Producing Activities.
Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The natural gas and oil prices used to calculate the full cost ceiling are based on 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. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. At September 30, 2017, the ceiling exceeded the book value of the oil and gas properties by $286.4 million. In adjusting estimated future net cash flows for hedging under the ceiling test at September 30, 2017, 2016, and 2015, estimated future net cash flows were increased by $30.5 million, $215.3 million and $194.5 million, respectively.
On December 1, 2015, Seneca and IOG - CRV Marcellus, LLC (IOG), an affiliate of IOG Capital, LP, and funds managed by affiliates of Fortress Investment Group, LLC, executed a joint development agreement that allows IOG to participate in the development of certain oil and gas interests owned by Seneca in Elk, McKean and Cameron Counties, Pennsylvania. On June 13, 2016, Seneca and IOG executed an extension of the joint development agreement. Under the terms of the extended agreement, Seneca and IOG will jointly participate in a program to develop up to 75 Marcellus wells, with Seneca serving as program operator. IOG will hold an 80% working interest in all of the joint development wells. In total, IOG is expected to fund approximately $325 million for its 80% working interest in the 75 joint development wells. Of this amount, IOG has funded $262.6 million as of September 30, 2017, which includes $163.9 million of cash ($137.3 million in fiscal 2016 and $26.6 million in fiscal 2017) that Seneca had received in recognition of IOG funding that is due to Seneca for costs previously incurred to develop a portion of the first 75 joint development wells. The cash proceeds were recorded by Seneca as a $163.9 million reduction of property, plant and equipment. The remainder funded joint development expenditures. As the fee-owner of the property’s mineral rights, Seneca retains a 7.5% royalty interest and the remaining 20% working interest (which results in a 26% net revenue interest) in 56 of the joint development wells. In the remaining 19 wells, Seneca retains a 20% working and net revenue interest. Seneca’s working interest under the agreement will increase to 85% after IOG achieves a 15% internal rate of return.
The principal assets of the Utility and Pipeline and Storage segments, consisting primarily of gas plant in service, are recorded at the historical cost when originally devoted to service.
Maintenance and repairs of property and replacements of minor items of property are charged directly to maintenance expense. The original cost of the regulated subsidiaries’ property, plant and equipment retired, and the cost of removal less salvage, are charged to accumulated depreciation.
Depreciation, Depletion and Amortization
For oil and gas properties, depreciation, depletion and amortization is computed based on quantities produced in relation to proved reserves using the units of production method. The cost of unproved oil and gas properties is excluded from this computation. In the All Other category, for timber properties, depletion, determined on a property by property basis, is charged to operations based on the actual amount of timber cut in relation to the total amount of recoverable timber. For all other property, plant and equipment, depreciation and amortization is computed using the straight-line method in amounts sufficient to recover costs over the estimated service lives of property in service. The following is a summary of depreciable plant by segment:
 
As of September 30
 
2017
 
2016
 
(Thousands)
Exploration and Production
$
4,925,409

 
$
4,645,226

Pipeline and Storage
2,002,736

 
1,956,708

Gathering
484,768

 
454,343

Utility
2,045,074

 
1,998,605

Energy Marketing
3,564

 
3,528

All Other and Corporate
109,128

 
109,455

 
$
9,570,679

 
$
9,167,865


Average depreciation, depletion and amortization rates are as follows:
 
Year Ended September 30
 
2017
 
2016
 
2015
Exploration and Production, per Mcfe(1)
$
0.65

 
$
0.87

 
$
1.52

Pipeline and Storage
2.2
%
 
2.4
%
 
2.4
%
Gathering
3.4
%
 
4.0
%
 
4.0
%
Utility
2.8
%
 
2.7
%
 
2.6
%
Energy Marketing
7.9
%
 
7.9
%
 
6.1
%
All Other and Corporate
1.3
%
 
1.8
%
 
1.4
%
 
(1)
Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note M — Supplementary Information for Oil and Gas Producing Activities, depletion of oil and gas producing properties amounted to $0.63, $0.85 and $1.49 per Mcfe of production in 2017, 2016 and 2015, respectively.
Goodwill
The Company has recognized goodwill of $5.5 million as of September 30, 2017 and 2016 on its Consolidated Balance Sheets related to the Company’s acquisition of Empire in 2003. The Company accounts for goodwill in accordance with the current authoritative guidance, which requires the Company to test goodwill for impairment annually. At September 30, 2017, 2016 and 2015, the fair value of Empire was greater than its book value. As such, the goodwill was not considered impaired at those dates. Going back to the origination of the goodwill in 2003, the Company has never recorded an impairment of its goodwill balance.
Financial Instruments
Unrealized gains or losses from the Company’s investments in an equity mutual fund, a fixed income mutual fund and the stock of an insurance company (securities available for sale) are recorded as a component of accumulated other comprehensive income (loss). Reference is made to Note G — Financial Instruments for further discussion.
The Company uses a variety of derivative financial instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil and to manage a portion of the risk of currency fluctuations associated with transportation costs denominated in Canadian currency. These instruments include price swap agreements and futures contracts. The Company accounts for these instruments as either cash flow hedges or fair value hedges. In both cases, the fair value of the instrument is recognized on the Consolidated Balance Sheets as either an asset or a liability labeled Fair Value of Derivative Financial Instruments. Reference is made to Note F — Fair Value Measurements for further discussion concerning the fair value of derivative financial instruments.
For effective cash flow hedges, the offset to the asset or liability that is recorded is a gain or loss recorded in accumulated other comprehensive income (loss) on the Consolidated Balance Sheets. The gain or loss recorded in accumulated other comprehensive income (loss) remains there until the hedged transaction occurs, at which point the gains or losses are reclassified to operating revenues, purchased gas expense or operation and maintenance expense on the Consolidated Statements of Income. Reference is made to Note G - Financial Instruments for further discussion concerning cash flow hedges.
For fair value hedges, the offset to the asset or liability that is recorded is a gain or loss recorded to operating revenues or purchased gas expense on the Consolidated Statements of Income. However, in the case of fair value hedges, the Company also records an asset or liability on the Consolidated Balance Sheets representing the change in fair value of the asset or firm commitment that is being hedged (see Other Current Assets section in this footnote). The offset to this asset or liability is a gain or loss recorded to operating revenues or purchased gas expense on the Consolidated Statements of Income as well. If the fair value hedge is effective, the gain or loss from the derivative financial instrument is offset by the gain or loss that arises from the change in fair value of the asset or firm commitment that is being hedged. Reference is made to Note G - Financial Instruments for further discussion concerning fair value hedges.
Accumulated Other Comprehensive Income (Loss)
The components of Accumulated Other Comprehensive Income (Loss) and changes for the year ended September 30, 2017, net of related tax effect, are as follows (amounts in parentheses indicate debits) (in thousands):
 
Gains and Losses on Derivative Financial Instruments
 
Gains and Losses on Securities Available for Sale
 
Funded Status of the Pension and Other Post-Retirement Benefit Plans
 
Total
Year Ended September 30, 2017
 
 
 
 
 
 
 
Balance at October 1, 2016
$
64,782

 
$
6,054

 
$
(76,476
)
 
$
(5,640
)
Other Comprehensive Gains and Losses Before Reclassifications
3,338

 
2,503

 
9,486

 
15,327

Amounts Reclassified From Other Comprehensive Loss
(47,319
)
 
(995
)
 
8,504

 
(39,810
)
Balance at September 30, 2017
$
20,801

 
$
7,562

 
$
(58,486
)
 
$
(30,123
)
 
 
 
 
 
 
 
 
Year Ended September 30, 2016
 
 
 
 
 
 
 
Balance at October 1, 2015
$
157,197

 
$
5,969

 
$
(69,794
)
 
$
93,372

Other Comprehensive Gains and Losses Before Reclassifications
41,845

 
932

 
(13,027
)
 
29,750

Amounts Reclassified From Other Comprehensive Loss
(134,260
)
 
(847
)
 
6,345

 
(128,762
)
Balance at September 30, 2016
$
64,782

 
$
6,054

 
$
(76,476
)
 
$
(5,640
)

The amounts included in accumulated other comprehensive income (loss) related to the funded status of the Company’s pension and other post-retirement benefit plans consist of prior service costs and accumulated losses. The total amount for prior service cost was $1.2 million and $1.3 million at September 30, 2017 and 2016, respectively. The total amount for accumulated losses was $57.3 million and $75.2 million at September 30, 2017 and 2016, respectively.
Reclassifications Out of Accumulated Other Comprehensive Income (Loss) 
The details about the reclassification adjustments out of accumulated other comprehensive loss for the year ended September 30, 2017 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands):
Details About Accumulated Other
Comprehensive Income (Loss) Components
 
Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) for the
Year Ended
September 30,
 
Affected Line Item in the Statement Where Net Income (Loss) is Presented
 
 
2017
 
2016
 
 
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
 
 
 
 
 
 
Commodity Contracts
 

$83,983

 

$216,823

 
Operating Revenues
Commodity Contracts
 
(1,921
)
 
4,520

 
Purchased Gas
Foreign Currency Contracts
 
(457
)
 
(424
)
 
Operation and Maintenance Expense
Gains (Losses) on Securities Available for Sale
 
1,575

 
1,374

 
Other Income
Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans:
 
 
 
 
 
 
Prior Service Credit
 
(288
)
 
(333
)
 
(1)
Net Actuarial Loss
 
(13,145
)
 
(9,735
)
 
(1)
 
 
69,747

 
212,225

 
Total Before Income Tax
 
 
(29,937
)
 
(83,463
)
 
Income Tax Expense
 
 

$39,810

 

$128,762

 
Net of Tax
 
(1)
These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost. Refer to Note H — Retirement Plan and Other Post-Retirement Benefits for additional details.
Gas Stored Underground 
In the Utility segment, gas stored underground in the amount of $26.7 million is carried at lower of cost or net realizable value, on a LIFO method. Based upon the average price of spot market gas purchased in September 2017, including transportation costs, the current cost of replacing this inventory of gas stored underground exceeded the amount stated on a LIFO basis by approximately $17.1 million at September 30, 2017. All other gas stored underground, which is in the Energy Marketing segment, is carried at an average cost method, subject to lower of cost or net realizable value adjustments.
Unamortized Debt Expense
Costs associated with the reacquisition of debt related to rate-regulated subsidiaries are deferred and amortized over the remaining life of the issue or the life of the replacement debt in order to match regulatory treatment. At September 30, 2017, the remaining weighted average amortization period for such costs was approximately 2 years.
Income Taxes
The Company and its subsidiaries file a consolidated federal income tax return. State tax returns are filed on a combined or separate basis depending on the applicable laws in the jurisdictions where tax returns are filed. The investment tax credit, prior to its repeal in 1986, was deferred and is being amortized over the estimated useful lives of the related property, as required by regulatory authorities having jurisdiction.
The Company follows the asset and liability approach in accounting for income taxes, which requires the recognition of deferred income taxes for the expected future tax consequences of net operating losses, credits and temporary differences between the financial statement carrying amounts and the tax basis of assets and liabilities. A valuation allowance is provided on deferred tax assets if it is determined, within each taxing jurisdiction, that it is more likely than not that the asset will not be realized.
The Company reports a liability or a reduction of deferred tax assets for unrecognized tax benefits resulting from uncertain tax positions taken or expected to be taken in a tax return. When applicable, the Company recognizes interest relating to uncertain tax positions in Other Interest Expense and penalties in Other Income.
Consolidated Statement of Cash Flows
For purposes of the Consolidated Statement of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of generally three months or less to be cash equivalents.
Hedging Collateral Deposits
This is an account title for cash held in margin accounts funded by the Company to serve as collateral for hedging positions. In accordance with its accounting policy, the Company does not offset hedging collateral deposits paid or received against related derivative financial instrument liability or asset balances.
Other Current Assets
The components of the Company’s Other Current Assets are as follows: 
 
Year Ended September 30
 
2017
 
2016
 
(Thousands)
Prepayments
$
10,927

 
$
10,919

Prepaid Property and Other Taxes
13,974

 
13,138

Federal Income Taxes Receivable

 
11,758

State Income Taxes Receivable
9,689

 
3,961

Fair Values of Firm Commitments
1,031

 
3,962

Regulatory Assets
15,884

 
15,616

 
$
51,505

 
$
59,354

Other Accruals and Current Liabilities
The components of the Company’s Other Accruals and Current Liabilities are as follows:
 
Year Ended September 30
 
2017
 
2016
 
(Thousands)
Accrued Capital Expenditures
$
37,382

 
$
26,796

Regulatory Liabilities
34,059

 
14,725

Federal Income Taxes Payable
1,775

 

Other
38,673

 
32,909

 
$
111,889

 
$
74,430

Customer Advances
The Company’s Utility and Energy Marketing segments have balanced billing programs whereby customers pay their estimated annual usage in equal installments over a twelve-month period. Monthly payments under the balanced billing programs are typically higher than current month usage during the summer months. During the winter months, monthly payments under the balanced billing programs are typically lower than current month usage. At September 30, 2017 and 2016, customers in the balanced billing programs had advanced excess funds of $15.7 million and $14.8 million, respectively.
Customer Security Deposits
The Company, in its Utility, Pipeline and Storage, and Energy Marketing segments, often times requires security deposits from marketers, producers, pipeline companies, and commercial and industrial customers before providing services to such customers. At September 30, 2017 and 2016, the Company had received customer security deposits amounting to $20.4 million and $16.0 million, respectively.
Earnings Per Common Share
Basic earnings per common share is computed by dividing income or loss by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the potentially dilutive securities the Company has outstanding are stock options, SARs, restricted stock units and performance shares. For the year ended September 30, 2017, the diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method. Stock options, SARs, restricted stock units and performance shares that are antidilutive are excluded from the calculation of diluted earnings per common share. There were 157,649 shares excluded as being antidilutive for the year ended September 30, 2017. As the Company recognized net losses for the years ended September 30, 2016 and 2015, the aforementioned potentially dilutive securities, amounting to 431,408 shares and 709,063 shares, respectively, were not recognized in the diluted earnings per share calculation for 2016 and 2015.
Stock-Based Compensation
The Company has various stock option and stock award plans which provide or provided for the issuance of one or more of the following to key employees: incentive stock options, nonqualified stock options, SARs, restricted stock, restricted stock units, performance units or performance shares. The Company follows authoritative guidance which requires the measurement and recognition of compensation cost at fair value for all share-based payments. Stock options and SARs under all plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no stock option or SAR is exercisable less than one year or more than ten years after the date of each grant. The Company has chosen the Black-Scholes-Merton closed form model to calculate the compensation expense associated with stock options and SARs. For all Company stock awards, forfeitures are recognized as they occur.
Restricted stock is subject to restrictions on vesting and transferability. Restricted stock awards entitle the participants to full dividend and voting rights. The market value of restricted stock on the date of the award is recorded as compensation expense over the vesting period. Certificates for shares of restricted stock awarded under the Company’s stock option and stock award plans are held by the Company during the periods in which the restrictions on vesting are effective. Restrictions on restricted stock awards generally lapse ratably over a period of not more than ten years after the date of each grant. Restricted stock units also are subject to restrictions on vesting and transferability. Restricted stock units, both performance and non-performance based, represent the right to receive shares of common stock of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company) at the end of a specified time period. The performance based and non-performance based restricted stock units do not entitle the participants to dividend and voting rights. The accounting for performance based and non-performance based restricted stock units is the same as the accounting for restricted share awards, except that the fair value at the date of grant of the restricted stock units (represented by the market value of Company common stock on the date of the award) must be reduced by the present value of forgone dividends over the vesting term of the award. The fair value of restricted stock units on the date of award is recorded as compensation expense over the vesting period.
Performance shares are an award constituting units denominated in common stock of the Company, the number of which may be adjusted over a performance cycle based upon the extent to which performance goals have been satisfied. Earned performance shares may be distributed in the form of shares of common stock of the Company, an equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company. The performance shares do not entitle the participant to receive dividends during the vesting period. For performance shares based on a return on capital goal, the fair value at the date of grant of the performance shares is determined by multiplying the expected number of performance shares to be issued by the market value of Company common stock on the date of grant reduced by the present value of forgone dividends. For performance shares based on a total shareholder return goal, the Company uses the Monte Carlo simulation technique to estimate the fair value price at the date of grant.
Refer to Note E — Capitalization and Short-Term Borrowings under the heading “Stock Option and Stock Award Plans” for additional disclosures related to stock-based compensation awards for all plans.
New Authoritative Accounting and Financial Reporting Guidance
In May 2014, the FASB issued authoritative guidance regarding revenue recognition. The authoritative guidance provides a single, comprehensive revenue recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The original effective date of this authoritative guidance was as of the Company's first quarter of fiscal 2018. However, the FASB has delayed the effective date of the new revenue standard by one year, and the guidance will now be effective as of the Company's first quarter of fiscal 2019. Working towards this implementation date, the Company is currently evaluating the guidance and the various issues identified by industry based revenue recognition task forces. The Company does not believe that its revenue recognition policies will change materially, although the Company is still assessing the impact. The Company will need to enhance its financial statement disclosures to comply with the new authoritative guidance.
In May 2015, the FASB issued authoritative guidance related to the presentation of investments for which fair value was measured using net asset value per share (or its equivalent). In fiscal 2017, the Company adopted this authoritative guidance. As a result, the presentation of Retirement Plan Investments and Other Post-Retirement Benefit Assets has been adjusted (see tables in Note H — Retirement Plan and Other Post-Retirement Benefits).
In February 2016, the FASB issued authoritative guidance requiring organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by all leases, regardless of whether they are considered to be capital leases or operating leases. The FASB’s previous authoritative guidance required organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by capital leases while excluding operating leases from balance sheet recognition. The new authoritative guidance will be effective as of the Company’s first quarter of fiscal 2020, with early adoption permitted. The Company does not anticipate early adoption and is currently evaluating the provisions of the revised guidance.
In March 2016, the FASB issued authoritative guidance simplifying several aspects of the accounting for stock-based compensation. The Company adopted this guidance effective as of October 1, 2016, recognizing a cumulative effect adjustment that increased retained earnings by $31.9 million. The cumulative effect represents the tax benefit of previously unrecognized tax deductions in excess of stock compensation recorded for financial reporting purposes. On a prospective basis, the tax effect of all future differences between stock compensation recorded for financial reporting purposes and actual tax deductions for stock compensation will be recognized upon vesting or settlement as income tax expense or benefit in the income statement. From a statement of cash flows perspective, the tax benefits relating to differences between stock compensation recorded for financial reporting purposes and actual tax deductions for stock compensation are now included in cash provided by operating activities instead of cash provided by financing activities. The changes to the statement of cash flows have been applied prospectively and prior periods have not been adjusted.
In March 2017, the FASB issued authoritative guidance related to the presentation of net periodic pension cost and net periodic postretirement benefit cost. The new guidance requires segregation of the service cost component from the other components of net periodic pension cost and net periodic postretirement benefit cost for financial reporting purposes. The service cost component is to be presented on the income statement in the same line items as other compensation costs included within Operating Expenses and the other components of net periodic pension cost and net periodic postretirement benefit cost are to be presented on the income statement below the subtotal labeled Operating Income (Loss). Under this guidance, the service cost component shall be the only component eligible to be capitalized as part of the cost of inventory or property, plant and equipment. The new guidance will be effective as of the Company’s first quarter of fiscal 2019, with early adoption permitted. The Company does not anticipate early adoption and is currently evaluating the interaction of this authoritative guidance with the various regulatory provisions concerning pension and postretirement benefit costs in the Company’s Utility and Pipeline and Storage segments.
Summary Of Significant Accounting Policies (Tables)
The following is a summary of depreciable plant by segment:
 
As of September 30
 
2017
 
2016
 
(Thousands)
Exploration and Production
$
4,925,409

 
$
4,645,226

Pipeline and Storage
2,002,736

 
1,956,708

Gathering
484,768

 
454,343

Utility
2,045,074

 
1,998,605

Energy Marketing
3,564

 
3,528

All Other and Corporate
109,128

 
109,455

 
$
9,570,679

 
$
9,167,865

Average depreciation, depletion and amortization rates are as follows:
 
Year Ended September 30
 
2017
 
2016
 
2015
Exploration and Production, per Mcfe(1)
$
0.65

 
$
0.87

 
$
1.52

Pipeline and Storage
2.2
%
 
2.4
%
 
2.4
%
Gathering
3.4
%
 
4.0
%
 
4.0
%
Utility
2.8
%
 
2.7
%
 
2.6
%
Energy Marketing
7.9
%
 
7.9
%
 
6.1
%
All Other and Corporate
1.3
%
 
1.8
%
 
1.4
%
 
(1)
Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note M — Supplementary Information for Oil and Gas Producing Activities, depletion of oil and gas producing properties amounted to $0.63, $0.85 and $1.49 per Mcfe of production in 2017, 2016 and 2015, respectively.
The components of Accumulated Other Comprehensive Income (Loss) and changes for the year ended September 30, 2017, net of related tax effect, are as follows (amounts in parentheses indicate debits) (in thousands):
 
Gains and Losses on Derivative Financial Instruments
 
Gains and Losses on Securities Available for Sale
 
Funded Status of the Pension and Other Post-Retirement Benefit Plans
 
Total
Year Ended September 30, 2017
 
 
 
 
 
 
 
Balance at October 1, 2016
$
64,782

 
$
6,054

 
$
(76,476
)
 
$
(5,640
)
Other Comprehensive Gains and Losses Before Reclassifications
3,338

 
2,503

 
9,486

 
15,327

Amounts Reclassified From Other Comprehensive Loss
(47,319
)
 
(995
)
 
8,504

 
(39,810
)
Balance at September 30, 2017
$
20,801

 
$
7,562

 
$
(58,486
)
 
$
(30,123
)
 
 
 
 
 
 
 
 
Year Ended September 30, 2016
 
 
 
 
 
 
 
Balance at October 1, 2015
$
157,197

 
$
5,969

 
$
(69,794
)
 
$
93,372

Other Comprehensive Gains and Losses Before Reclassifications
41,845

 
932

 
(13,027
)
 
29,750

Amounts Reclassified From Other Comprehensive Loss
(134,260
)
 
(847
)
 
6,345

 
(128,762
)
Balance at September 30, 2016
$
64,782

 
$
6,054

 
$
(76,476
)
 
$
(5,640
)
The details about the reclassification adjustments out of accumulated other comprehensive loss for the year ended September 30, 2017 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands):
Details About Accumulated Other
Comprehensive Income (Loss) Components
 
Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) for the
Year Ended
September 30,
 
Affected Line Item in the Statement Where Net Income (Loss) is Presented
 
 
2017
 
2016
 
 
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
 
 
 
 
 
 
Commodity Contracts
 

$83,983

 

$216,823

 
Operating Revenues
Commodity Contracts
 
(1,921
)
 
4,520

 
Purchased Gas
Foreign Currency Contracts
 
(457
)
 
(424
)
 
Operation and Maintenance Expense
Gains (Losses) on Securities Available for Sale
 
1,575

 
1,374

 
Other Income
Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans:
 
 
 
 
 
 
Prior Service Credit
 
(288
)
 
(333
)
 
(1)
Net Actuarial Loss
 
(13,145
)
 
(9,735
)
 
(1)
 
 
69,747

 
212,225

 
Total Before Income Tax
 
 
(29,937
)
 
(83,463
)
 
Income Tax Expense
 
 

$39,810

 

$128,762

 
Net of Tax
 
(1)
These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost. Refer to Note H — Retirement Plan and Other Post-Retirement Benefits for additional details.
The components of the Company’s Other Current Assets are as follows: 
 
Year Ended September 30
 
2017
 
2016
 
(Thousands)
Prepayments
$
10,927

 
$
10,919

Prepaid Property and Other Taxes
13,974

 
13,138

Federal Income Taxes Receivable

 
11,758

State Income Taxes Receivable
9,689

 
3,961

Fair Values of Firm Commitments
1,031

 
3,962

Regulatory Assets
15,884

 
15,616

 
$
51,505

 
$
59,354

The components of the Company’s Other Accruals and Current Liabilities are as follows:
 
Year Ended September 30
 
2017
 
2016
 
(Thousands)
Accrued Capital Expenditures
$
37,382

 
$
26,796

Regulatory Liabilities
34,059

 
14,725

Federal Income Taxes Payable
1,775

 

Other
38,673

 
32,909

 
$
111,889

 
$
74,430

Asset Retirement Obligations (Tables)
Schedule Of Change In Asset Retirement Obligation
The following is a reconciliation of the change in the Company’s asset retirement obligations:
 
Year Ended September 30
 
2017
 
2016
 
2015
 
(Thousands)
Balance at Beginning of Year
$
112,330

 
$
156,805

 
$
117,713

Liabilities Incurred
2,963

 
2,719

 
4,433

Revisions of Estimates
(10,578
)
 
16,721

 
33,717

Liabilities Settled
(4,967
)
 
(72,215
)
 
(6,825
)
Accretion Expense
6,647

 
8,300

 
7,767

Balance at End of Year
$
106,395

 
$
112,330

 
$
156,805

Regulatory Matters (Tables)
Schedule Of Regulatory Assets And Liabilities
The Company has recorded the following regulatory assets and liabilities:
 
At September 30
 
2017
 
2016
 
(Thousands)
Regulatory Assets(1):
 
 
 
Pension Costs(2) (Note H)
$
125,175

 
$
203,755

Post-Retirement Benefit Costs(2) (Note H)
13,886

 
74,802

Recoverable Future Taxes (Note D)
181,363

 
177,261

Environmental Site Remediation Costs(2) (Note I)
19,665

 
23,392

Asset Retirement Obligations(2) (Note B)
12,764

 
12,490

Unamortized Debt Expense (Note A)
1,159

 
1,688

Other(3)
18,827

 
21,927

Total Regulatory Assets
372,839

 
515,315

Less: Amounts Included in Other Current Assets
(15,884
)
 
(15,616
)
Total Long-Term Regulatory Assets
$
356,955

 
$
499,699

 
 
At September 30
 
2017
 
2016
 
(Thousands)
Regulatory Liabilities:
 
 
 
Cost of Removal Regulatory Liability
$
204,630

 
$
193,424

Taxes Refundable to Customers (Note D)
95,739

 
93,318

Post-Retirement Benefit Costs (Note H)
102,891

 
67,204

Amounts Payable to Customers (See Regulatory Mechanisms in Note A)

 
19,537

Other(4)
44,884

 
47,310

Total Regulatory Liabilities
448,144

 
420,793

Less: Amounts included in Current and Accrued Liabilities
(34,059
)
 
(34,262
)
Total Long-Term Regulatory Liabilities
$
414,085

 
$
386,531

 
(1)
The Company recovers the cost of its regulatory assets but generally does not earn a return on them. There are a few exceptions to this rule. For example, the Company does earn a return on Unrecovered Purchased Gas Costs and, in the New York jurisdiction of its Utility segment, earns a return, within certain parameters, on the excess of cumulative funding to the pension plan over the cumulative amount collected in rates.
(2)
Included in Other Regulatory Assets on the Consolidated Balance Sheets.
(3)
$15,884 and $15,616 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2017 and 2016, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $2,943 and $6,311 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2017 and 2016, respectively.
(4)
$34,059 and $14,725 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2017 and 2016, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $10,825 and $32,585 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2017 and 2016, respectively.
Income Taxes (Tables)
The components of federal and state income taxes included in the Consolidated Statements of Income are as follows:
 
Year Ended September 30
 
2017
 
2016
 
2015
 
(Thousands)
Current Income Taxes —
 
 
 
 
 
Federal
$
32,034

 
$
(6,658
)
 
$
25,064

State
10,673

 
20,903

 
13,387

Deferred Income Taxes —
 
 
 
 
 
Federal
103,046

 
(164,818
)
 
(244,336
)
State
14,929

 
(81,976
)
 
(113,251
)
 
160,682

 
(232,549
)
 
(319,136
)
Deferred Investment Tax Credit
(173
)
 
(348
)
 
(414
)
Total Income Taxes
$
160,509

 
$
(232,897
)
 
$
(319,550
)
Presented as Follows:
 
 
 
 
 
Other Income
$
(173
)
 
$
(348
)
 
$
(414
)
Income Tax Expense (Benefit)
160,682

 
(232,549
)
 
(319,136
)
Total Income Taxes
$
160,509

 
$
(232,897
)
 
$
(319,550
)
The following is a reconciliation of this difference:
 
Year Ended September 30
 
2017
 
2016
 
2015
 
(Thousands)
U.S. Income (Loss) Before Income Taxes
$
443,991

 
$
(523,855
)
 
$
(698,977
)
Income Tax Expense (Benefit), Computed at U.S. Federal Statutory Rate of 35%
$
155,397

 
$
(183,349
)
 
$
(244,642
)
State Income Taxes (Benefit)
16,641

 
(39,697
)
 
(64,912
)
Federal Tax Credits
(6,679
)
 
(3,262
)
 
(732
)
Miscellaneous
(4,850
)
 
(6,589
)
 
(9,264
)
Total Income Taxes
$
160,509

 
$
(232,897
)
 
$
(319,550
)
Significant components of the Company’s deferred tax liabilities and assets were as follows:
 
At September 30
 
2017
 
2016
 
(Thousands)
Deferred Tax Liabilities:
 
 
 
Property, Plant and Equipment
$
1,141,432

 
$
1,049,100

Pension and Other Post-Retirement Benefit Costs
79,516

 
151,903

Unrealized Hedging Gains
19,127

 
50,179

Other
57,919

 
55,457

Total Deferred Tax Liabilities
1,297,994

 
1,306,639

Deferred Tax Assets:
 
 
 
Pension and Other Post-Retirement Benefit Costs
(123,532
)
 
(195,829
)
Tax Loss and Credit Carryforwards
(200,344
)
 
(194,875
)
Other
(82,831
)
 
(92,140
)
Total Deferred Tax Assets
(406,707
)
 
(482,844
)
Total Net Deferred Income Taxes
$
891,287

 
$
823,795

The following is a reconciliation of the change in unrecognized tax benefits:
 
Year Ended September 30
 
2017
 
2016
 
2015
 
(Thousands)
Balance at Beginning of Year
$
396

 
$
5,085

 
$
3,147

Additions for Tax Positions of Prior Years
1,251

 
396

 
2,504

Reductions for Tax Positions of Prior Years
(396
)
 
(1,314
)
 
(566
)
Reductions Related to Settlements with Taxing Authorities

 
(3,771
)
 

Balance at End of Year
$
1,251

 
$
396

 
$
5,085

As of September 30, 2017, the Company has the following carryforwards available:
Jurisdiction
 
Tax Attribute
 
Amount
(Thousands)
 
Expires
Federal
 
Net Operating Loss
 
$
184,289

 
2028-2033
Pennsylvania
 
Net Operating Loss
 
324,572

 
2030-2035
California
 
Net Operating Loss
 
169,723

 
2029-2035
Federal
 
Alternative Minimum Tax Credit
 
81,683

 
Unlimited
California
 
Alternative Minimum Tax Credit
 
5,873

 
Unlimited
Federal
 
Enhanced Oil Recovery Credit
 
10,502

 
2029-2037
California
 
Enhanced Oil Recovery Credit
 
5,061

 
2021-2037
Federal
 
R&D Tax Credit
 
5,694

 
2031-2036
Capitalization And Short-Term Borrowings (Tables)
Summary of Changes in Common Stock Equity
 
Common Stock
 
Paid In
Capital
 
Earnings
Reinvested
in the
Business
 
Accumulated
Other
Comprehensive
Income (Loss)
Shares
 
Amount
 
 
(Thousands, except per share amounts)
Balance at September 30, 2014
84,157

 
$
84,157

 
$
716,144

 
$
1,614,361

 
$
(3,979
)
Net Income (Loss) Available for Common Stock
 
 
 
 
 
 
(379,427
)
 
 
Dividends Declared on Common Stock ($1.56 Per Share)
 
 
 
 
 
 
(131,734
)
 
 
Other Comprehensive Income, Net of Tax
 
 
 
 
 
 
 
 
97,351

Share-Based Payment Expense(2)
 
 
 
 
2,207

 
 
 
 
Common Stock Issued Under Stock and Benefit Plans(1)
437

 
437

 
25,923

 
 
 
 
Balance at September 30, 2015
84,594

 
84,594

 
744,274

 
1,103,200

 
93,372

Net Income (Loss) Available for Common Stock
 
 
 
 
 
 
(290,958
)
 
 
Dividends Declared on Common Stock ($1.60 Per Share)
 
 
 
 
 
 
(135,881
)
 
 
Other Comprehensive Loss, Net of Tax
 
 
 
 
 
 
 
 
(99,012
)
Share-Based Payment Expense(2)
 
 
 
 
4,843

 
 
 
 
Common Stock Issued Under Stock and Benefit Plans(1)
525

 
525

 
22,047

 
 
 
 
Balance at September 30, 2016
85,119

 
85,119

 
771,164

 
676,361

 
(5,640
)
Net Income Available for Common Stock
 
 
 
 
 
 
283,482

 
 
Dividends Declared on Common Stock ($1.64 Per Share)
 
 
 
 
 
 
(140,090
)
 
 
Cumulative Effect of Adoption of Authoritative Guidance for Stock-Based Compensation
 
 
 
 
 
 
31,916

 
 
Other Comprehensive Loss, Net of Tax
 
 
 
 
 
 
 
 
(24,483
)
Share-Based Payment Expense(2)
 
 
 
 
10,902

 
 
 
 
Common Stock Issued Under Stock and Benefit Plans
424

 
424

 
14,580

 
 
 
 
Balance at September 30, 2017
85,543

 
$
85,543

 
$
796,646

 
$
851,669

(3)
$
(30,123
)
 
(1)
Paid in Capital includes tax benefits of $1.9 million and $9.1 million for September 30, 2016 and 2015, respectively, related to stock-based compensation.
(2)
Paid in Capital includes compensation costs associated with stock option, SARs, performance share and/or restricted stock awards. The expense is included within Net Income Available For Common Stock, net of tax benefits.
(3)
The availability of consolidated earnings reinvested in the business for dividends payable in cash is limited under terms of the indentures covering long-term debt. At September 30, 2017, $707.5 million of accumulated earnings was free of such limitations.
Transactions involving option shares for all plans are summarized as follows:
 
Number of
Shares Subject
to Option
 
Weighted
Average
Exercise Price
 
Weighted
Average
Remaining
Contractual
Life (Years)
 
Aggregate
Intrinsic
Value
(In thousands)
Outstanding at September 30, 2016
19,000

 
$
39.48

 
 
 
 
Granted in 2017

 
$

 
 
 
 
Exercised in 2017
(19,000
)
 
$
39.48

 
 
 
 
Forfeited in 2017

 
$

 
 
 
 
Outstanding at September 30, 2017

 
$

 

 
$

Option shares exercisable at September 30, 2017

 
$

 

 
$

Shares available for future grant at September 30, 2017(1)
2,182,243

 
 
 
 
 
 
 
(1)
Includes shares available for options, SARs, restricted stock and performance share grants.
Transactions involving SARs for all plans are summarized as follows:
 
Number of
Shares Subject
To Option
 
Weighted
Average
Exercise Price
 
Weighted
Average
Remaining
Contractual
Life (Years)
 
Aggregate
Intrinsic
Value
(In thousands)
Outstanding at September 30, 2016
1,590,988

 
$
48.19

 
 
 
 
Granted in 2017

 
$

 
 
 
 
Exercised in 2017
(82,077
)
 
$
39.77

 
 
 
 
Forfeited in 2017

 
$

 
 
 
 
Expired in 2017
(3,000
)
 
$
52.10

 
 
 
 
Outstanding at September 30, 2017
1,505,911

 
$
48.64

 
2.52
 
$
13,144

SARs exercisable at September 30, 2017
1,505,911

 
$
48.64

 
2.52
 
$
13,144

Transactions involving restricted share awards for all plans are summarized as follows: 
 
Number of
Restricted
Share Awards
 
Weighted Average
Fair Value per
Award
Outstanding at September 30, 2016
20,000

 
$
47.46

Granted in 2017

 
$

Vested in 2017

 
$

Forfeited in 2017

 
$

Outstanding at September 30, 2017
20,000

 
$
47.46

Transactions involving non-performance based restricted stock units for all plans are summarized as follows:
 
Number of
Restricted
Stock Units
 
Weighted Average
Fair Value per
Award
Outstanding at September 30, 2016
239,151

 
$
49.67

Granted in 2017
87,143

 
$
52.13

Vested in 2017
(80,530
)
 
$
53.38

Forfeited in 2017
(12,565
)
 
$
53.75

Outstanding at September 30, 2017
233,199

 
$
48.99

Transactions involving performance shares for all plans are summarized as follows:
 
Number of
Performance
Shares
 
Weighted Average
Fair Value per
Award
Outstanding at September 30, 2016
438,234

 
$
44.98

Granted in 2017
184,148

 
$
56.39

Vested in 2017
(43,484
)
 
$
69.13

Forfeited in 2017
(51,150
)
 
$
60.74

Outstanding at September 30, 2017
527,748

 
$
45.44

The outstanding long-term debt is as follows:
 
At September 30
 
2017
 
2016
 
(Thousands)
Medium-Term Notes(1):
 
 
 
7.4% due March 2023 to June 2025
$
99,000

 
$
99,000

Notes(1)(3)(4):
 
 
 
3.75% to 8.75% due April 2018 to September 2027
2,300,000

 
2,000,000

Total Long-Term Debt
2,399,000

 
2,099,000

Less Unamortized Discount and Debt Issuance Costs
15,319

 
12,748

Less Current Portion(2)
300,000

 

 
$
2,083,681

 
$
2,086,252

 
(1)
The Medium-Term Notes and Notes are unsecured.
(2)
Current Portion of Long-Term Debt at September 30, 2017 consisted of $300.0 million of 6.50% notes scheduled to mature in April 2018. The Company redeemed these notes on October 18, 2017 for $307.0 million, plus accrued interest. The call premium was recorded to Unamortized Debt Expense on the Consolidated Balance Sheet in October 2017.
(3)
The holders of these notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade.
(4)
The interest rate payable on $300.0 million of 3.95% notes will be subject to adjustment from time to time, with a maximum of 2.00%, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to below investment grade (or if the credit rating assigned to the notes is subsequently upgraded).
The following assumptions were used in estimating the fair value of the TSR performance shares at the date of grant:
 
Year Ended September 30
 
2017
 
2016
 
2015
Risk-Free Interest Rate
1.54
%
 
1.26
%
 
1.01
%
Remaining Term at Date of Grant (Years)
2.79

 
2.79

 
2.78

Expected Volatility
22.6
%
 
20.5
%
 
20.1
%
Expected Dividend Yield (Quarterly)
N/A

 
N/A

 
N/A

Fair Value Measurements (Tables)
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis
The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities (as applicable) that were accounted for at fair value on a recurring basis as of September 30, 2017 and 2016. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The fair value presentation for over-the-counter swaps combines gas and oil swaps because a significant number of the counterparties enter into both gas and oil swap agreements with the Company. 
 
At Fair Value as of September 30, 2017
Recurring Fair Value Measures
Level 1
 
Level 2
 
Level 3
 
Netting
Adjustments(1)
 
Total(1)
 
(Dollars in thousands)
Assets:
 
 
 
 
 
 
 
 
 
Cash Equivalents — Money Market Mutual Funds
$
527,978

 
$

 
$

 
$

 
$
527,978

Derivative Financial Instruments:
 
 
 
 
 
 
 
 
 
Commodity Futures Contracts — Gas
1,483

 

 

 
(963
)
 
520

Over the Counter Swaps — Gas and Oil

 
38,977

 

 
(4,206
)
 
34,771

Foreign Currency Contracts

 
1,227

 

 
(407
)
 
820

Other Investments:
 
 
 
 
 
 
 
 

Balanced Equity Mutual Fund
37,033

 

 

 

 
37,033

Fixed Income Mutual Fund
45,727

 

 

 

 
45,727

Common Stock — Financial Services Industry
3,150

 

 

 

 
3,150

Hedging Collateral Deposits
1,741

 

 

 

 
1,741

Total
$
617,112

 
$
40,204

 
$

 
$
(5,576
)
 
$
651,740

Liabilities:
 
 
 
 
 
 
 
 
 
Derivative Financial Instruments:
 
 
 
 
 
 
 
 
 
Commodity Futures Contracts — Gas
$
963

 
$

 
$

 
$
(963
)
 
$

Over the Counter Swaps — Gas and Oil

 
5,309

 

 
(4,206
)
 
1,103

Foreign Currency Contracts

 
407

 

 
(407
)
 

Total
$
963

 
$
5,716

 
$

 
$
(5,576
)
 
$
1,103

Total Net Assets/(Liabilities)
$
616,149

 
$
34,488

 
$

 
$

 
$
650,637


 
At Fair Value as of September 30, 2016
Recurring Fair Value Measures
Level 1
 
Level 2
 
Level 3
 
Netting
Adjustments(1)
 
Total(1)
 
(Dollars in thousands)
Assets:
 
 
 
 
 
 
 
 
 
Cash Equivalents — Money Market Mutual Funds
$
113,407

 
$

 
$

 
$

 
$
113,407

Derivative Financial Instruments:
 
 
 
 
 
 
 
 
 
Commodity Futures Contracts — Gas
2,623

 

 

 
(2,276
)
 
347

Over the Counter Swaps — Gas and Oil

 
119,654

 

 
(3,860
)
 
115,794

Foreign Currency Contracts

 

 

 
(2,337
)
 
(2,337
)
Other Investments:
 
 
 
 
 
 
 
 
 
Balanced Equity Mutual Fund
36,658

 

 

 

 
36,658

Fixed Income Mutual Fund
31,395

 

 

 

 
31,395

Common Stock — Financial Services Industry
2,902

 

 

 

 
2,902

Hedging Collateral Deposits
1,484

 

 

 

 
1,484

Total
$
188,469


$
119,654


$


$
(8,473
)

$
299,650

Liabilities:
 
 
 
 
 
 
 
 
 
Derivative Financial Instruments:
 
 
 
 
 
 
 
 
 
Commodity Futures Contracts — Gas
$
2,276

 
$

 
$

 
$
(2,276
)
 
$

Over the Counter Swaps — Gas and Oil

 
5,322

 

 
(3,860
)
 
1,462

Foreign Currency Contracts

 
2,337

 

 
(2,337
)
 

Total
$
2,276

 
$
7,659

 
$

 
$
(8,473
)
 
$
1,462

Total Net Assets/(Liabilities)
$
186,193

 
$
111,995

 
$

 
$

 
$
298,188

 
(1)
Netting Adjustments represent the impact of legally-enforceable master netting arrangements that allow the Company to net gain and loss positions held with the same counterparties. The net asset or net liability for each counterparty is recorded as an asset or liability on the Company’s balance sheet.
Financial Instruments (Tables)
Based on these criteria, the fair market value of long-term debt, including current portion, was as follows:
 
 
At September 30
 
2017 Carrying
Amount
 
2017 Fair
Value
 
2016 Carrying
Amount
 
2016 Fair
Value
 
(Thousands)
Long-Term Debt
$
2,383,681

 
$
2,523,639

 
$
2,086,252

 
$
2,255,562

The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Year Ended September 30, 2017 and 2016 (Dollar Amounts in Thousands)
Derivatives in Cash
Flow Hedging
Relationships
 
Amount of
Derivative Gain or
(Loss) Recognized
in Other
Comprehensive
Income (Loss) on
the Consolidated
Statement of
Comprehensive
Income (Loss)
(Effective Portion)
for the Year Ended
September 30,
 
Location of
Derivative Gain or (Loss) Reclassified
from Accumulated
Other Comprehensive
Income (Loss) on
the Consolidated
Balance Sheet into the Consolidated
Statement of Income
(Effective Portion)
 
Amount of
Derivative Gain or
(Loss) Reclassified
from Accumulated
Other
Comprehensive
Income (Loss) on
the Consolidated
Balance Sheet into
the Consolidated
Statement of Income
(Effective Portion)
for the Year Ended
September 30,
 
Location of
Derivative Gain or (Loss) Recognized
in the Consolidated
Statement of Income
(Ineffective Portion
and Amount
Excluded from
Effectiveness Testing)
 
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness  Testing) for the Year Ended September 30,
 
 
2017
 
2016
 
 
 
2017
 
2016
 
 
 
2017
 
2016
Commodity Contracts
 
$
2,811

 
$
58,714

 
Operating Revenue
 
$
83,983

 
$
216,823

 
Operating Revenue
 
$
(100
)
 
$
392

Commodity Contracts
 
(164
)
 
1,585

 
Purchased Gas
 
(1,921
)
 
4,520

 
Not Applicable
 

 

Foreign Currency Contracts
 
2,700

 
194

 
Operation and Maintenance Expense
 
(457
)
 
(424
)
 
Not Applicable
 

 

Total
 
$
5,347

 
$
60,493

 
 
 
$
81,605

 
$
220,919

 
 
 
$
(100
)
 
$
392

For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk completely offset each other in current earnings, as shown below.
Derivatives in Fair Value Hedging Relationships
 
Location of Gain or (Loss) on Derivative and Hedged Item Recognized in the Consolidated Statement of Income
 
Amount of Gain or
(Loss) on Derivative
Recognized in the
Consolidated
Statement of Income
for the Year Ended
September 30, 2017
 
Amount of Gain or
(Loss) on Hedged Item
Recognized in the
Consolidated
Statement of Income
for the Year Ended
September 30, 2017
 
 
 
 
(In thousands)
Commodity Contracts
 
Operating Revenues
 
$
1,655

 
$
(1,655
)
Commodity Contracts
 
Purchased Gas
 
464

 
(464
)
 
 
 
 
$
2,119

 
$
(2,119
)
Retirement Plan And Other Post-Retirement Benefits (Tables)
Reconciliations of the Benefit Obligations, Plan Assets and Funded Status, as well as the components of Net Periodic Benefit Cost and the Weighted Average Assumptions of the Retirement Plan and other post-retirement benefits are shown in the tables below. The date used to measure the Benefit Obligations, Plan Assets and Funded Status is September 30 for fiscal years 2017, 2016 and 2015.
 
Retirement Plan
 
Other Post-Retirement Benefits
 
Year Ended September 30
 
Year Ended September 30
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
 
(Thousands)
Change in Benefit Obligation
 
 
 
 
 
 
 
 
 
 
 
Benefit Obligation at Beginning of Period
$
1,097,421

 
$
1,026,190

 
$
999,499

 
$
526,138

 
$
464,987

 
$
465,583

Service Cost
11,969

 
11,710

 
12,047

 
2,449

 
2,331

 
2,693

Interest Cost
38,383

 
42,315

 
41,217

 
19,007

 
20,386

 
19,285

Plan Participants’ Contributions

 

 

 
2,717

 
2,558

 
2,242

Retiree Drug Subsidy Receipts

 

 

 
1,553

 
1,925

 
1,338

Amendments(1)

 

 
7,752

 

 

 

Actuarial (Gain) Loss
(32,466
)
 
76,309

 
23,426

 
(62,215
)
 
60,402

 
(1,575
)
Benefits Paid
(60,481
)
 
(59,103
)
 
(57,751
)
 
(27,030
)
 
(26,451
)
 
(24,579
)
Benefit Obligation at End of Period
$
1,054,826

 
$
1,097,421

 
$
1,026,190

 
$
462,619

 
$
526,138

 
$
464,987

Change in Plan Assets
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Assets at Beginning of Period
$
869,775

 
$
834,870

 
$
869,791

 
$
494,320

 
$
477,959

 
$
497,601

Actual Return on Plan Assets
84,279

 
87,008

 
(13,370
)
 
40,157

 
37,415

 
534

Employer Contributions
17,146

 
7,000

 
36,200

 
3,853

 
2,839

 
2,161

Plan Participants’ Contributions

 

 

 
2,717

 
2,558

 
2,242

Benefits Paid
(60,481
)
 
(59,103
)
 
(57,751
)
 
(27,030
)
 
(26,451
)
 
(24,579
)
Fair Value of Assets at End of Period
$
910,719

 
$
869,775

 
$
834,870

 
$
514,017

 
$
494,320

 
$
477,959

Net Amount Recognized at End of Period (Funded Status)
$
(144,107
)
 
$
(227,646
)
 
$
(191,320
)
 
$
51,398

 
$
(31,818
)
 
$
12,972

Amounts Recognized in the Balance Sheets Consist of:
 
 
 
 
 
 
 
 
 
 
 
Non-Current Liabilities
$
(144,107
)
 
$
(227,646
)
 
$
(191,320
)
 
$
(4,972
)
 
$
(49,467
)
 
$
(11,487
)
Non-Current Assets

 

 

 
56,370

 
17,649

 
24,459

Net Amount Recognized at End of Period
$
(144,107
)
 
$
(227,646
)
 
$
(191,320
)
 
$
51,398

 
$
(31,818
)
 
$
12,972

Accumulated Benefit Obligation
$
1,010,179

 
$
1,039,408

 
$
968,984

 
N/A

 
N/A

 
N/A

Weighted Average Assumptions Used to Determine Benefit Obligation at September 30
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
3.77
%
 
3.60
%
 
4.25
%
 
3.81
%
 
3.70
%
 
4.50
%
Rate of Compensation Increase
4.70
%
 
4.70
%
 
4.75
%
 
4.70
%
 
4.70
%
 
4.75
%
 
Retirement Plan
 
Other Post-Retirement Benefits
 
Year Ended September 30
 
Year Ended September 30
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
 
(Thousands)
Components of Net Periodic Benefit Cost
 
 
 
 
 
 
 
 
 
 
 
Service Cost
$
11,969

 
$
11,710

 
$
12,047

 
$
2,449

 
$
2,331

 
$
2,693

Interest Cost
38,383

 
42,315

 
41,217

 
19,007

 
20,386

 
19,285

Expected Return on Plan Assets
(59,718
)
 
(59,369
)
 
(59,615
)
 
(31,458
)
 
(31,535
)
 
(34,089
)
Amortization of Prior Service Cost (Credit)
1,058

 
1,234

 
183

 
(429
)
 
(912
)
 
(1,913
)
Recognition of Actuarial Loss(2)
42,687

 
32,248

 
36,129

 
18,415

 
5,530

 
4,148

Net Amortization and Deferral for Regulatory Purposes
469

 
3,957

 
7,739

 
6,108

 
17,123

 
20,322

Net Periodic Benefit Cost
$
34,848

 
$
32,095

 
$
37,700

 
$
14,092

 
$
12,923

 
$
10,446

Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
3.60
%
 
4.25
%
 
4.25
%
 
3.70
%
 
4.50
%
 
4.25
%
Expected Return on Plan Assets
7.00
%
 
7.25
%
 
7.50
%
 
6.50
%
 
6.75
%
 
7.00
%
Rate of Compensation Increase
4.75
%
 
4.75
%
 
4.75
%
 
4.75
%
 
4.75
%
 
4.75
%
 
(1)
In fiscal 2015, the Company passed an amendment which updated the mortality table used in the Retirement Plan's definition of "actuarially equivalent" effective July 1, 2015. This increased the benefit obligation of the Retirement Plan.
(2)
Distribution Corporation’s New York jurisdiction calculates the amortization of the actuarial loss on a vintage year basis over 10 years, as mandated by the NYPSC. All the other subsidiaries of the Company utilize the corridor approach.
The cumulative amounts recognized in accumulated other comprehensive income (loss), regulatory assets, and regulatory liabilities through fiscal 2017, the changes in such amounts during 2017, as well as the amounts expected to be recognized in net periodic benefit cost in fiscal 2018 are presented in the table below:
 
Retirement
Plan
 
Other
Post-Retirement
Benefits
 
Non-Qualified
Benefit Plans
 
(Thousands)
Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities(1)
 
 
 
 
 
Net Actuarial Loss
$
(203,887
)
 
$
(19,578
)
 
$
(24,332
)
Prior Service (Cost) Credit
(6,133
)
 
3,687

 

Net Amount Recognized
$
(210,020
)
 
$
(15,891
)
 
$
(24,332
)
Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2017(1)
 
 
 
 
 
Decrease (Increase) in Actuarial Loss, excluding amortization(2)
$
57,028

 
$
70,915

 
$
(1,351
)
Change due to Amortization of Actuarial Loss
42,687

 
18,415

 
4,059

Prior Service (Cost) Credit
1,058

 
(429
)
 

Net Change
$
100,773

 
$
88,901

 
$
2,708

Amounts Expected to be Recognized in Net Periodic Benefit Cost in the Next Fiscal Year(1)
 
 
 
 
 
Net Actuarial Loss
$
(37,205
)
 
$
(10,558
)
 
$
(3,549
)
Prior Service (Cost) Credit
(938
)
 
429

 

Net Amount Expected to be Recognized
$
(38,143
)
 
$
(10,129
)
 
$
(3,549
)
 
(1)
Amounts presented are shown before recognizing deferred taxes.
(2)
Amounts presented include the impact of actuarial gains/losses related to return on assets, as well as the Actuarial (Gain) Loss amounts presented in the Change in Benefit Obligation.
The estimated gross other post-retirement benefit payments and gross amount of Medicare Part D prescription drug subsidy receipts are as follows (dollars in thousands):

 
Benefit Payments
 
Subsidy Receipts
2018
$
26,483

 
$
(1,910
)
2019
$
27,456

 
$
(2,074
)
2020
$
28,359

 
$
(2,225
)
2021
$
29,173

 
$
(2,369
)
2022
$
29,757

 
$
(2,515
)
2023 through 2027
$
152,957

 
$
(14,271
)
Assumed health care cost trend rates as of September 30 were:
 
2017
 
 
2016
 
 
2015
 
Rate of Medical Cost Increase for Pre Age 65 Participants
5.67
%
(1)
 
5.75
%
(1)
 
6.93
%
(2)
Rate of Medical Cost Increase for Post Age 65 Participants
4.75
%
(1)
 
4.75
%
(1)
 
6.68
%
(2)
Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits
8.45
%
(1)
 
9.00
%
(1)
 
7.17
%
(2)
Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement
4.75
%
(1)
 
4.75
%
(1)
 
6.68
%
(2)
Annual Rate of Increase in the Per Capita Medicare Part D Subsidy
7.33
%
(1)
 
7.20
%
(1)
 
6.65
%
(2)
 
(1)
It was assumed that this rate would gradually decline to 4.5% by 2039.
(2)
It was assumed that this rate would gradually decline to 4.5% by 2028.
 
Total Fair
 Value Amounts at
September 30, 2017
 
Level 1
 
Level 2
 
Level 3
 
Measured at NAV(7)
Retirement Plan Investments
 
 
 
 
 
 
 
 
 
Domestic Equities(1)
$
290,716

 
$
209,421

 
$

 
$

 
$
81,295

International Equities(2)
123,069

 

 

 

 
123,069

Global Equities(3)
121,008

 

 

 

 
121,008

Domestic Fixed Income(4)
348,501

 
1,664

 
346,837

 

 

International Fixed Income(5)
422

 
422

 

 

 

Global Fixed Income(6)
75,428

 

 

 

 
75,428

Real Estate
3,391

 

 

 
3,391

 

Cash Held in Collective Trust Funds
26,058

 

 

 

 
26,058

Total Retirement Plan Investments
988,593

 
211,507

 
346,837

 
3,391

 
426,858

401(h) Investments
(64,728
)
 
(14,026
)
 
(23,001
)
 
(225
)
 
(27,476
)
Total Retirement Plan Investments (excluding 401(h) Investments)
$
923,865

 
$
197,481

 
$
323,836

 
$
3,166

 
$
399,382

Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash
(13,146
)
 
 
 
 
 
 
 
 
Total Retirement Plan Assets
$
910,719

 
 
 
 
 
 
 
 
 
 
Total Fair 
Value
Amounts at
September 30, 2016
 
Level 1
 
Level 2
 
Level 3
 
Measured at NAV(7)
Retirement Plan Investments
 
 
 
 
 
 
 
 
 
Domestic Equities(1)
$
256,796

 
$
188,253

 
$

 
$

 
$
68,543

International Equities(2)
104,592

 

 

 

 
104,592

Global Equities(3)
120,025

 

 

 

 
120,025

Domestic Fixed Income(4)
342,442

 
1,647

 
340,795

 

 

International Fixed Income(5)
744

 
407

 
337

 

 

Global Fixed Income(6)
81,146

 

 

 

 
81,146

Real Estate
2,970

 

 

 
2,970

 

Cash Held in Collective Trust Funds
24,812

 

 

 

 
24,812

Total Retirement Plan Investments
933,527

 
190,307

 
341,132

 
2,970

 
399,118

401(h) Investments
(58,707
)
 
(12,025
)
 
(21,555
)
 
(188
)
 
(24,939
)
Total Retirement Plan Investments (excluding 401(h) Investments)
$
874,820

 
$
178,282

 
$
319,577

 
$
2,782

 
$
374,179

Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash
(5,045
)
 
 
 
 
 
 
 
 
Total Retirement Plan Assets
$
869,775

 
 
 
 
 
 
 
 
 
(1)
Domestic Equities include mostly collective trust funds, common stock, and exchange traded funds.
(2)
International Equities are comprised of collective trust funds.
(3)
Global Equities are comprised of collective trust funds.
(4)
Domestic Fixed Income securities include mostly collective trust funds, corporate/government bonds and mortgages, and exchange traded funds.
(5)
International Fixed Income securities are comprised mostly of an exchange traded fund.
(6)
Global Fixed Income securities are comprised of a collective trust fund.
(7)
Reflects the adoption of the new authoritative guidance related to investments measured at the net asset value (NAV) practical expedient.
 
 
Retirement Plan Level 3 Assets
(Thousands)
 
 
Hedge
Funds
 
Real
Estate
 
Excluding
401(h)
Investments
 
Total
 
 
 
Balance at September 30, 2015
$
26,490

 
$
4,724

 
$
(1,885
)
 
$
29,329

 
Realized Gains/(Losses)
5,878

 

 
(354
)
 
5,524

 
Unrealized Gains/(Losses)
(5,445
)
 
(404
)
 
344

 
(5,505
)
 
Sales
(26,923
)
 
(1,350
)
 
1,707

 
(26,566
)
 
Balance at September 30, 2016

 
2,970


(188
)

2,782

 
Unrealized Gains/(Losses)

 
421

 
(37
)
 
384

 
Balance at September 30, 2017
$

 
$
3,391

 
$
(225
)
 
$
3,166

 
Total Fair
 Value
Amounts at
September 30, 2017
 
Level 1
 
Level 2
 
Level 3
 
Measured at NAV(1)
Other Post-Retirement Benefit Assets held in VEBA Trusts
 
 
 
 
 
 
 
 
 
Collective Trust Funds — Domestic Equities
$
130,864

 
$

 
$

 
$

 
$
130,864

Collective Trust Funds — International Equities
52,063

 

 

 

 
52,063

Exchange Traded Funds — Fixed Income
256,099

 
256,099

 

 

 

Cash Held in Collective Trust Funds
9,569

 

 

 

 
9,569

Total VEBA Trust Investments
448,595

 
256,099

 

 

 
192,496

401(h) Investments
64,728

 
14,026

 
23,001

 
225

 
27,476

Total Investments (including 401(h) Investments)
$
513,323

 
$
270,125

 
$
23,001

 
$
225

 
$
219,972

Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative)
694

 
 
 
 
 
 
 
 
Total Other Post-Retirement Benefit Assets
$
514,017

 
 
 
 
 
 
 
 
 
 
Total Fair
 Value
Amounts at
September 30, 2016
 
Level 1
 
Level 2
 
Level 3
 
Measured at NAV(1)
Other Post-Retirement Benefit Assets held in VEBA Trusts
 
 
 
 
 
 
 
 
 
Collective Trust Funds — Domestic Equities
$
139,617

 
$

 
$

 
$

 
$
139,617

Collective Trust Funds — International Equities
51,488

 

 

 

 
51,488

Exchange Traded Funds — Fixed Income
230,761

 
230,761

 

 

 

Cash Held in Collective Trust Funds
13,176

 

 

 

 
13,176

Total VEBA Trust Investments
435,042

 
230,761

 

 

 
204,281

401(h) Investments
58,707

 
12,025

 
21,555

 
188

 
24,939

Total Investments (including 401(h) Investments)
$
493,749

 
$
242,786

 
$
21,555

 
$
188

 
$
229,220

Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative)
571

 
 
 
 
 
 
 
 
Total Other Post-Retirement Benefit Assets
$
494,320

 
 
 
 
 
 
 
 

 
(1)
Reflects the adoption of the new authoritative guidance related to investments measured at the net asset value (NAV) practical expedient.
 
 
Other Post-Retirement Benefit Level 3 Assets
(Thousands)
 
 
401(h)
Investments
 
 
Balance at September 30, 2015
 
$
1,885

Realized Gains/(Losses)
 
354

Unrealized Gains/(Losses)
 
(344
)
Sales
 
(1,707
)
Balance at September 30, 2016
 
188

Unrealized Gains/(Losses)
 
37

Balance at September 30, 2017
 
$
225

Business Segment Information (Tables)
 
Year Ended September 30, 2017
 
Exploration
and
Production
 
Pipeline
and
Storage
 
Gathering
 
Utility
 
Energy
Marketing
 
Total
Reportable
Segments
 
All
Other
 
Corporate
and
Intersegment
Eliminations
 
Total
Consolidated
 
(Thousands)
Revenue from External Customers(1)
$
614,599

 
$
206,615

 
$
115

 
$
626,899

 
$
128,586

 
$
1,576,814

 
$
2,173

 
$
894

 
$
1,579,881

Intersegment Revenues
$

 
$
87,810

 
$
107,566

 
$
13,072

 
$
794

 
$
209,242

 
$

 
$
(209,242
)
 
$

Interest Income
$
707

 
$
1,467

 
$
994

 
$
1,051

 
$
571

 
$
4,790

 
$
213

 
$
(890
)
 
$
4,113

Interest Expense
$
53,702

 
$
33,717

 
$
9,142

 
$
28,492

 
$
47

 
$
125,100

 
$

 
$
(5,263
)
 
$
119,837

Depreciation, Depletion and Amortization
$
112,565

 
$
41,196

 
$
16,162

 
$
52,582

 
$
279

 
$
222,784

 
$
661

 
$
750

 
$
224,195

Income Tax Expense (Benefit)
$
66,093

 
$
40,947

 
$
29,694

 
$
24,894

 
$
891

 
$
162,519

 
$
(247
)
 
$
(1,590
)
 
$
160,682

Segment Profit: Net Income (Loss)
$
129,326

 
$
68,446

 
$
40,377

 
$
46,935

 
$
1,509

 
$
286,593

 
$
(342
)
 
$
(2,769
)
 
$
283,482

Expenditures for Additions to Long-Lived Assets
$
253,057

 
$
95,336

 
$
32,645

 
$
80,867

 
$
36

 
$
461,941

 
$
39

 
$
137

 
$
462,117

 
At September 30, 2017
 
(Thousands)
Segment Assets
$
1,407,152

 
$
1,929,788

 
$
580,051

 
$
2,013,123

 
$
60,937

 
$
5,991,051

 
$
76,861

 
$
35,408

 
$
6,103,320

 
 
Year Ended September 30, 2016
 
Exploration
and
Production
 
Pipeline
and
Storage
 
Gathering
 
Utility
 
Energy
Marketing
 
Total
Reportable
Segments
 
All
Other
 
Corporate
and
Intersegment
Elimination
 
Total
Consolidated
 
(Thousands)
Revenue from External Customers(1)
$
607,113

 
$
215,674

 
$
374

 
$
531,024

 
$
93,578

 
$
1,447,763

 
$
3,753

 
$
900

 
$
1,452,416

Intersegment Revenues
$

 
$
90,755

 
$
89,073

 
$
13,123

 
$
884

 
$
193,835

 
$

 
$
(193,835
)
 
$

Interest Income
$
858

 
$
770

 
$
297

 
$
1,737

 
$
422

 
$
4,084

 
$
117

 
$
34

 
$
4,235

Interest Expense
$
55,434

 
$
33,327

 
$
8,872

 
$
27,582

 
$
49

 
$
125,264

 
$

 
$
(4,220
)
 
$
121,044

Depreciation, Depletion and Amortization
$
139,963

 
$
43,273

 
$
15,282

 
$
48,618

 
$
278

 
$
247,414

 
$
1,260

 
$
743

 
$
249,417

Income Tax Expense (Benefit)
$
(334,029
)
 
$
50,241

 
$
24,334

 
$
25,602

 
$
2,460

 
$
(231,392
)
 
$
561

 
$
(1,718
)
 
$
(232,549
)
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties
$
948,307

 
$

 
$

 
$

 
$

 
$
948,307

 
$

 
$

 
$
948,307

Segment Profit: Net Income (Loss)
$
(452,842
)
 
$
76,610

 
$
30,499

 
$
50,960

 
$
4,348

 
$
(290,425
)
 
$
778

 
$
(1,311
)
 
$
(290,958
)
Expenditures for Additions to Long-Lived Assets
$
256,104

 
$
114,250

 
$
54,293

 
$
98,007

 
$
34

 
$
522,688

 
$
37

 
$
326

 
$
523,051

 
At September 30, 2016
 
(Thousands)
Segment Assets
$
1,323,081

 
$
1,680,734

 
$
534,259

 
$
2,021,514

 
$
63,392

 
$
5,622,980

 
$
77,138

 
$
(63,731
)
 
$
5,636,387

 
 
Year Ended September 30, 2015
 
Exploration
and
Production
 
Pipeline
and
Storage
 
Gathering
 
Utility
 
Energy
Marketing
 
Total
Reportable
Segments
 
All
Other
 
Corporate
and
Intersegment
Eliminations
 
Total
Consolidated
 
(Thousands)
Revenue from External Customers(1)
$
693,441

 
$
203,089

 
$
497

 
$
700,761

 
$
159,857

 
$
1,757,645

 
$
2,352

 
$
916

 
$
1,760,913

Intersegment Revenues
$

 
$
88,251

 
$
76,709

 
$
15,506

 
$
849

 
$
181,315

 
$

 
$
(181,315
)
 
$

Interest Income
$
2,554

 
$
474

 
$
140

 
$
2,220

 
$
195

 
$
5,583

 
$
66

 
$
(1,727
)
 
$
3,922

Interest Expense
$
46,726

 
$
27,658

 
$
1,627

 
$
28,176

 
$
27

 
$
104,214

 
$

 
$
(4,743
)
 
$
99,471

Depreciation, Depletion and Amortization
$
239,818

 
$
38,178

 
$
10,829

 
$
45,616

 
$
209

 
$
334,650

 
$
832

 
$
676

 
$
336,158

Income Tax Expense (Benefit)
$
(428,217
)
 
$
48,113

 
$
24,721

 
$
33,143

 
$
4,547

 
$
(317,693
)
 
$
13

 
$
(1,456
)
 
$
(319,136
)
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties
$
1,126,257

 
$

 
$

 
$

 
$

 
$
1,126,257

 
$

 
$

 
$
1,126,257

Segment Profit: Net Income (Loss)
$
(556,974
)
 
$
80,354

 
$
31,849

 
$
63,271

 
$
7,766

 
$
(373,734
)
 
$
(2
)
 
$
(5,691
)
 
$
(379,427
)
Expenditures for Additions to Long-Lived Assets
$
557,313

 
$
230,192

 
$
118,166

 
$
94,371

 
$
128

 
$
1,000,170

 
$

 
$
339

 
$
1,000,509

 
At September 30, 2015
 
(Thousands)
Segment Assets
$
2,439,801

 
$
1,590,524

 
$
444,358

 
$
1,934,731

 
$
90,676

 
$
6,500,090

 
$
77,350

 
$
(12,501
)
 
$
6,564,939

 
(1)
All Revenue from External Customers originated in the United States.
Geographic Information
At September 30
 
2017
 
2016
 
2015
 
(Thousands)
Long-Lived Assets:
 
 
 
 
 
United States
$
5,285,040

 
$
5,223,356

 
$
6,189,138

Quarterly Financial Data (Tables)
Schedule Of Quarterly Financial Information
 
Quarter Ended
Operating
Revenues
 
Operating
Income (Loss)
 
Net 
Income (Loss)
Available for
Common Stock
 
Earnings (Loss) per
Common Share
 
 
Basic
 
Diluted
 
 
(Thousands, except per common share amounts)
 
2017
 
 
 
 
 
 
 
 
 
 
9/30/2017
$
286,937

 
$
87,395

 
$
45,577

 
$
0.53

 
$
0.53

 
6/30/2017
$
348,369

 
$
123,354

 
$
59,714

 
$
0.70

 
$
0.69

 
3/31/2017
$
522,075

 
$
169,957

 
$
89,283

 
$
1.05

 
$
1.04

 
12/31/2016
$
422,500

 
$
172,139

 
$
88,908

 
$
1.04

 
$
1.04

 
2016
 
 
 
 
 
 
 
 
 
 
9/30/2016
$
292,472

 
$
81,244

 
$
37,553

(1)
$
0.44

 
$
0.44

 
6/30/2016
$
335,617

 
$
45,162

 
$
8,286

(2)
$
0.10

 
$
0.10

 
3/31/2016
$
449,132

 
$
(237,000
)
 
$
(147,688
)
(3)
$
(1.74
)
 
$
(1.74
)
 
12/31/2015
$
375,195

 
$
(305,924
)
 
$
(189,109
)
(4)
$
(2.23
)
 
$
(2.23
)
 
(1)
Includes a non-cash $32.7 million impairment charge ($19.0 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
(2)
Includes a non-cash $82.7 million impairment charge ($47.9 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
(3)
Includes a non-cash $397.4 million impairment charge ($230.5 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
(4)
Includes a non-cash $435.5 million impairment charge ($252.6 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
Supplementary Information For Oil And Gas Producing Activities (Tables)
Capitalized Costs Relating to Oil and Gas Producing Activities
 
At September 30
 
2017
 
2016
 
(Thousands)
Proved Properties(1)
$
4,832,301

 
$
4,554,929

Unproved Properties
80,932

 
135,285

 
4,913,233

 
4,690,214

Less — Accumulated Depreciation, Depletion and Amortization
3,765,710

 
3,657,239

 
$
1,147,523

 
$
1,032,975

 
(1)
Includes asset retirement costs of $54.4 million and $63.6 million at September 30, 2017 and 2016, respectively.
Following is a summary of costs excluded from amortization at September 30, 2017:
 
Total as of
September 30,
2017
 
Year Costs Incurred
 
 
2017
 
2016
 
2015
 
Prior
 
(Thousands)
Acquisition Costs
$
55,193

 
$

 
$

 
$

 
$
55,193

Development Costs
11,879

 
4,388

 
6,707

 
416

 
368

Exploration Costs
13,388

 
2,376

 
7,593

 
3,419

 

Capitalized Interest
472

 
235

 
149

 
88

 

 
$
80,932

 
$
6,999

 
$
14,449

 
$
3,923

 
$
55,561

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
 
Year Ended September 30
 
2017
 
2016
 
2015
 
(Thousands)
United States
 
Property Acquisition Costs:
 
 
 
 
 
Proved
$
8,908

 
$
1,342

 
$
1,767

Unproved
262

 
2,165

 
19,998

Exploration Costs(1)
40,975

 
27,561

 
53,222

Development Costs(2)
200,639

 
219,386

 
454,605

Asset Retirement Costs
(9,175
)
 
(49,653
)
 
37,595

 
$
241,609

 
$
200,801

 
$
567,187

 
(1)
Amounts for 2017, 2016 and 2015 include capitalized interest of $0.3 million, $0.3 million and $0.4 million, respectively.
(2)
Amounts for 2017, 2016 and 2015 include capitalized interest of $0.2 million, $0.2 million and $0.5 million, respectively.
Results of Operations for Producing Activities
 
Year Ended September 30
 
2017
 
2016
 
2015
United States
(Thousands, except per Mcfe amounts)
Operating Revenues:
 
 
 
 
 
Natural Gas (includes transfers to operations of $2,357, $1,765 and $1,946, respectively)(1)
$
399,975

 
$
282,619

 
$
350,673

Oil, Condensate and Other Liquids
126,517

 
103,533

 
156,048

Total Operating Revenues(2)
526,492

 
386,152

 
506,721

Production/Lifting Costs
165,991

 
153,914

 
167,800

Franchise/Ad Valorem Taxes
15,372

 
13,794

 
20,167

Purchased Emission Allowance Expense
1,391

 
700

 
3,089

Accretion Expense
4,896

 
6,663

 
6,186

Depreciation, Depletion and Amortization ($0.63, $0.85 and $1.49 per Mcfe of production, respectively)
108,471

 
136,579

 
234,480

Impairment of Oil and Gas Producing Properties

 
948,307

 
1,126,257

Income Tax Expense (Benefit)
86,657

 
(368,940
)
 
(444,393
)
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)
$
143,714

 
$
(504,865
)
 
$
(606,865
)
 
(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.
 
Gas MMcf
 
U. S.
 
 
 
Appalachian
Region
 
West Coast
Region
 
Total
Company
Proved Developed and Undeveloped Reserves:
 
 
 
 
 
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

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

Proved Developed Reserves:
 
 
 
 


September 30, 2014
1,119,901

  
57,907

 
1,177,808

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

Proved Undeveloped Reserves:
 
 
 
 


September 30, 2014
504,161

  
915

 
505,076

September 30, 2015
825,284

  

 
825,284

September 30, 2016
541,959

  

 
541,959

September 30, 2017
610,018

  

 
610,018

 
(1)
Extensions and discoveries include 598 Bcf (during 2015), 179 Bcf (during 2016) and 181 Bcf (during 2017), of Marcellus Shale gas in the Appalachian region.
(2)
Production includes 130,291 MMcf (during 2015), 135,598 MMcf (during 2016) and 145,452 MMcf (during 2017), 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, 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

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

Proved Developed Reserves:
 
 
 
 

September 30, 2014
253

 
37,002

 
37,255

September 30, 2015
220

 
33,150

 
33,370

September 30, 2016
73

 
28,698

 
28,771

September 30, 2017
28

 
29,771

 
29,799

Proved Undeveloped Reserves:
 
 
 
 


September 30, 2014

 
1,222

 
1,222

September 30, 2015

 
352

 
352

September 30, 2016

 
238

 
238

September 30, 2017

 
408

 
408

 
Year Ended September 30
 
2017
 
2016
 
2015
 
(Thousands)
United States
 
 
 
 
 
Future Cash Inflows
$
6,144,317

 
$
3,768,463

 
$
6,916,775

Less:
 
 
 
 
 
Future Production Costs
2,378,262

 
1,994,916

 
2,854,142

Future Development Costs
411,578

 
375,152

 
761,922

Future Income Tax Expense at Applicable Statutory Rate
1,160,469

 
303,397

 
1,117,433

Future Net Cash Flows
2,194,008

 
1,094,998

 
2,183,278

Less:
 
 
 
 
 
10% Annual Discount for Estimated Timing of Cash Flows
1,080,962

 
452,470

 
860,244

Standardized Measure of Discounted Future Net Cash Flows
$
1,113,046

 
$
642,528

 
$
1,323,034

The principal sources of change in the standardized measure of discounted future net cash flows were as follows:
 
Year Ended September 30
 
2017
 
2016
 
2015
 
(Thousands)
United States
 
 
 
 
 
Standardized Measure of Discounted Future
 
 
 
 
 
Net Cash Flows at Beginning of Year
$
642,528

 
$
1,323,034

 
$
2,066,878

Sales, Net of Production Costs
(345,075
)
 
(218,444
)
 
(318,753
)
Net Changes in Prices, Net of Production Costs
828,187

 
(1,066,593
)
 
(1,752,843
)
Extensions and Discoveries
170,500

 
47,742

 
266,159

Changes in Estimated Future Development Costs
8,816

 
143,752

 
164,510

Sales of Minerals in Place
(9,849
)
 
(95,849
)
 
(1
)
Previously Estimated Development Costs Incurred
101,134

 
92,840

 
161,833

Net Change in Income Taxes at Applicable Statutory Rate
(393,353
)
 
387,739

 
545,442

Revisions of Previous Quantity Estimates
39,078

 
6,202

 
(16,573
)
Accretion of Discount and Other
71,080

 
22,105

 
206,382

Standardized Measure of Discounted Future Net Cash Flows at End of Year
$
1,113,046

 
$
642,528

 
$
1,323,034

Summary Of Significant Accounting Policies (Narrative) (Details) (USD $)
3 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Dec. 31, 2015
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
Sep. 30, 2017
Amount Exceeds LIFO Basis [Member]
Sep. 30, 2017
LIFO Method [Member]
Sep. 30, 2017
Seneca [Member]
Sep. 30, 2016
Seneca [Member]
Jun. 13, 2016
IOG-CRV Marcellus, LLC [Member]
Sep. 30, 2017
Accumulated Losses [Member]
Sep. 30, 2016
Accumulated Losses [Member]
Sep. 30, 2017
Unamortized Debt Expense [Member]
Jun. 13, 2016
26 Percent Net Revenue Interest [Member]
Seneca [Member]
Jun. 13, 2016
After Achieved Internal Rate of Return [Member]
Seneca [Member]
Jun. 13, 2016
Extended Agreement [Member]
Seneca [Member]
Sep. 30, 2017
Extended Agreement [Member]
IOG-CRV Marcellus, LLC [Member]
Jun. 13, 2016
Extended Agreement [Member]
IOG-CRV Marcellus, LLC [Member]
Jun. 13, 2016
20 Percent Net Revenue Interest [Member]
Seneca [Member]
Summary Of Significant Accounting Policies [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Full cost ceiling test discount factor
 
 
 
 
10.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount full cost ceiling exceeds book value of oil and gas properties
 
 
 
 
$ 286,400,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Increase estimated future net cash flows
 
 
 
 
30,500,000 
215,300,000 
194,500,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Wells to be Developed
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
56 
 
 
 
75 
19 
Partner Working Interest In Joint Wells
 
 
 
 
 
 
 
 
 
 
 
80.00% 
 
 
 
 
85.00% 
20.00% 
 
 
 
Partner Commitment to Develop Joint Wells
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
325,000,000 
 
Partner Amount Funded to Develop Joint Wells
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
262,600,000 
 
 
Cumulative Net Proceeds from Sale of Oil and Gas Producing Properties
 
 
 
 
 
 
 
 
 
163,900,000 
 
 
 
 
 
 
 
 
 
 
 
Reduction in Property, Plant and Equipment
 
 
 
 
 
 
 
 
 
163,900,000 
 
 
 
 
 
 
 
 
 
 
 
Royalty Interest
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7.50% 
 
 
 
Partner Net Revenue Interest in Joint Wells
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
26.00% 
 
 
 
Net Proceeds from Sale of Oil and Gas Producing Properties
 
 
 
 
26,554,000 
137,316,000 
 
 
26,600,000 
137,300,000 
 
 
 
 
 
 
 
 
 
 
Partner Working and Net Revenue Interest In Joint Wells
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
20.00% 
 
 
 
Internal Rate of Return
 
 
 
 
 
 
 
 
 
 
 
15.00% 
 
 
 
 
 
 
 
 
 
Goodwill
5,476,000 
 
 
 
5,476,000 
5,476,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Prior service (cost) credit
(1,300,000)
 
 
 
(1,200,000)
(1,300,000)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated losses
 
 
 
 
 
 
 
 
 
 
 
 
57,300,000 
75,200,000 
 
 
 
 
 
 
 
Gas stored underground
34,332,000 
 
 
 
35,689,000 
34,332,000 
 
17,100,000 
26,700,000 
 
 
 
 
 
 
 
 
 
 
 
 
Regulated Reacquisition of Debt Cost Weighted Average Amortization Period
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2 years 
 
 
 
 
 
 
Customer Advances
14,762,000 
 
 
 
15,701,000 
14,762,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Customer Security Deposits
16,019,000 
 
 
 
20,372,000 
16,019,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Antidilutive securities
 
 
 
 
157,649 
431,408 
709,063 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cumulative Effect of Adoption of Authoritative Guidance for Stock-Based Compensation
 
 
 
 
31,900,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Impairment of Oil and Gas Producing Properties
32,700,000 
82,700,000 
397,400,000 
435,500,000 
948,307,000 
1,126,257,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Receivable from Sale of Oil and Gas Producing Properties
 
 
 
 
$ 0 
$ 19,543,000 
$ 0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Summary Of Significant Accounting Policies (Schedule Of Depreciable Plant By Segment) (Details) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2017
Sep. 30, 2016
Segment Reporting Information [Line Items]
 
 
Depreciable plant
$ 9,570,679 
$ 9,167,865 
Utility [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Depreciable plant
2,045,074 
1,998,605 
Pipeline And Storage [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Depreciable plant
2,002,736 
1,956,708 
Exploration And Production [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Depreciable plant
4,925,409 
4,645,226 
Energy Marketing [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Depreciable plant
3,564 
3,528 
Gathering [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Depreciable plant
484,768 
454,343 
All Other And Corporate [Member]
 
 
Segment Reporting Information [Line Items]
 
 
Depreciable plant
$ 109,128 
$ 109,455 
Summary Of Significant Accounting Policies (Average Depreciation Depletion And Amortization Rates) (Details) (USD $)
12 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
Exploration And Production [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Depreciation depletion and amortization rate per Mcfe
$ 0.65 1
$ 0.87 1
$ 1.52 1
Utility [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Average depreciation, depletion and amortization rates
2.80% 
2.70% 
2.60% 
Pipeline And Storage [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Average depreciation, depletion and amortization rates
2.20% 
2.40% 
2.40% 
Energy Marketing [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Average depreciation, depletion and amortization rates
7.90% 
7.90% 
6.10% 
Gathering [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Average depreciation, depletion and amortization rates
3.40% 
4.00% 
4.00% 
All Other And Corporate [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Average depreciation, depletion and amortization rates
1.30% 
1.80% 
1.40% 
Oil And Gas Producing Properties [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Depreciation depletion and amortization rate per Mcfe
$ 0.63 
$ 0.85 
$ 1.49 
Summary Of Significant Accounting Policies (Components Of Accumulated Other Comprehensive Income (Loss)) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Accumulated Other Comprehensive Income [Roll Forward]
 
 
Beginning balance
$ (5,640)
$ 93,372 
Other Comprehensive Gains and Losses Before Reclassifications
15,327 
29,750 
Amounts Reclassified From Other Comprehensive Loss
(39,810)
(128,762)
Ending balance
(30,123)
(5,640)
Gains and Losses on Derivative Financial Instruments [Member]
 
 
Accumulated Other Comprehensive Income [Roll Forward]
 
 
Beginning balance
64,782 
157,197 
Other Comprehensive Gains and Losses Before Reclassifications
3,338 
41,845 
Amounts Reclassified From Other Comprehensive Loss
(47,319)
(134,260)
Ending balance
20,801 
64,782 
Gains and Losses on Securities Available for Sale [Member]
 
 
Accumulated Other Comprehensive Income [Roll Forward]
 
 
Beginning balance
6,054 
5,969 
Other Comprehensive Gains and Losses Before Reclassifications
2,503 
932 
Amounts Reclassified From Other Comprehensive Loss
(995)
(847)
Ending balance
7,562 
6,054 
Funded Status of the Pension and Other Post-Retirement Benefit Plans [Member]
 
 
Accumulated Other Comprehensive Income [Roll Forward]
 
 
Beginning balance
(76,476)
(69,794)
Other Comprehensive Gains and Losses Before Reclassifications
9,486 
(13,027)
Amounts Reclassified From Other Comprehensive Loss
8,504 
6,345 
Ending balance
$ (58,486)
$ (76,476)
Summary Of Significant Accounting Policies Summary Of Significant Accounting Policies (Reclassification Out of Accumulated Other Comprehensive Income (Loss)) (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 12 Months Ended
Sep. 30, 2017
Jun. 30, 2017
Mar. 31, 2017
Dec. 31, 2016
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Dec. 31, 2015
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Operating Revenues
$ 286,937 
$ 348,369 
$ 522,075 
$ 422,500 
$ 292,472 
$ 335,617 
$ 449,132 
$ 375,195 
$ 1,579,881 
$ 1,452,416 
$ 1,760,913 
Purchased Gas
 
 
 
 
 
 
 
 
(275,254)
(147,982)
(349,984)
Other Income
 
 
 
 
 
 
 
 
7,043 
9,820 
8,039 
Income Before Income Taxes
 
 
 
 
 
 
 
 
444,164 
(523,507)
(698,563)
Income Tax Expense
 
 
 
 
 
 
 
 
(160,682)
232,549 
319,136 
Net Income (Loss) Available for Common Stock
45,577 
59,714 
89,283 
88,908 
37,553 1
8,286 2
(147,688)3
(189,109)4
283,482 
(290,958)
(379,427)
Amount Of Gain Or (Loss) Reclassified From Accumulated Other Comprehensive Income (Loss) [Member]
 
 
 
 
 
 
 
 
 
 
 
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Income Before Income Taxes
 
 
 
 
 
 
 
 
69,747 
212,225 
 
Income Tax Expense
 
 
 
 
 
 
 
 
(29,937)
(83,463)
 
Net Income (Loss) Available for Common Stock
 
 
 
 
 
 
 
 
39,810 
128,762 
 
Amount Of Gain Or (Loss) Reclassified From Accumulated Other Comprehensive Income (Loss) [Member] |
Gains and Losses on Securities Available for Sale [Member]
 
 
 
 
 
 
 
 
 
 
 
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Other Income
 
 
 
 
 
 
 
 
1,575 
1,374 
 
Amount Of Gain Or (Loss) Reclassified From Accumulated Other Comprehensive Income (Loss) [Member] |
Amortization of Prior Year Funded Status of Pension and Other Post-Retirement Benefit Plans [Member]
 
 
 
 
 
 
 
 
 
 
 
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Amortization of Prior Service Credit
 
 
 
 
 
 
 
 
(288)5
(333)5
 
Recognition of Net Actuarial Loss
 
 
 
 
 
 
 
 
(13,145)5
(9,735)5
 
Amount Of Gain Or (Loss) Reclassified From Accumulated Other Comprehensive Income (Loss) [Member] |
Commodity Contracts [Member] |
Gains and Losses on Derivative Financial Instruments [Member]
 
 
 
 
 
 
 
 
 
 
 
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Operating Revenues
 
 
 
 
 
 
 
 
83,983 
216,823 
 
Purchased Gas
 
 
 
 
 
 
 
 
(1,921)
4,520 
 
Foreign Currency Contracts [Member] |
Amount Of Gain Or (Loss) Reclassified From Accumulated Other Comprehensive Income (Loss) [Member] |
Gains and Losses on Derivative Financial Instruments [Member]
 
 
 
 
 
 
 
 
 
 
 
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Operation and Maintenance
 
 
 
 
 
 
 
 
$ (457)
$ (424)
 
Summary Of Significant Accounting Policies (Components Of Other Current Assets) (Details) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2017
Sep. 30, 2016
Summary Of Significant Accounting Policies [Line Items]
 
 
Prepayments
$ 10,927 
$ 10,919 
Prepaid Property and Other Taxes
13,974 
13,138 
Fair Values of Firm Commitments
1,031 
3,962 
Regulatory Assets
15,884 1
15,616 1
Other Current Assets
51,505 
59,354 
Federal [Member]
 
 
Summary Of Significant Accounting Policies [Line Items]
 
 
Income Taxes Receivable
11,758 
State [Member]
 
 
Summary Of Significant Accounting Policies [Line Items]
 
 
Income Taxes Receivable
$ 9,689 
$ 3,961 
Summary Of Significant Accounting Policies (Schedule Of Other Accruals And Current Liabilities) (Details) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2017
Sep. 30, 2016
Summary Of Significant Accounting Policies [Line Items]
 
 
Regulatory Liability
$ 34,059 
$ 34,262 
Other Accruals and Current Liabilities
111,889 
74,430 
Accrued Capital Expenditures [Member]
 
 
Summary Of Significant Accounting Policies [Line Items]
 
 
Other
37,382 
26,796 
Regulatory Liabilities [Member]
 
 
Summary Of Significant Accounting Policies [Line Items]
 
 
Regulatory Liability
34,059 
14,725 
Other Accruals [Member]
 
 
Summary Of Significant Accounting Policies [Line Items]
 
 
Other
38,673 
32,909 
Federal [Member]
 
 
Summary Of Significant Accounting Policies [Line Items]
 
 
Income Taxes Payable
$ 1,775 
$ 0 
Asset Retirement Obligation (Narrative) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
Asset Retirement Obligation [Line Items]
 
 
 
Liabilities Settled
$ 4,967 
$ 72,215 
$ 6,825 
Upper Devonian Wells [Member]
 
 
 
Asset Retirement Obligation [Line Items]
 
 
 
Liabilities Settled
 
$ 58,400 
 
Asset Retirement Obligations (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
 
 
 
Balance at Beginning of Year
$ 112,330 
$ 156,805 
$ 117,713 
Liabilities Incurred
2,963 
2,719 
4,433 
Revisions of Estimates
(10,578)
16,721 
33,717 
Liabilities Settled
(4,967)
(72,215)
(6,825)
Accretion Expense
6,647 
8,300 
7,767 
Balance at End of Year
$ 106,395 
$ 112,330 
$ 156,805 
Regulatory Matters (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2017
Regulatory Matters [Line Items]
 
Amount of requested increase to annual revenues
$ 41.7 
Recommended rate increase to annual revenues
8.5 
Recommended Equity Ratio
42.30% 
Recommended Cost of Equity
8.60% 
Approved Rate Increase
$ 5.9 
Approved Cost of Equity
8.70% 
Approved Equity Ratio
42.90% 
Regulatory Matters (Schedule Of Regulatory Assets And Liabilities) (Details) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2017
Sep. 30, 2016
Regulatory Assets And Liabilities [Line Items]
 
 
Total Regulatory Assets
$ 372,839 1
$ 515,315 1
Less: Amounts Included in Other Current Assets
(15,884)1
(15,616)1
Total Long-Term Regulatory Assets
174,433 
320,750 
Total Regulatory Liabilities
448,144 
420,793 
Less: Amounts Included in Current and Accrued Liabilities
(34,059)
(34,262)
Total Long-Term Regulatory Liabilities
113,716 
99,789 
Cost Of Removal Regulatory Liability [Member]
 
 
Regulatory Assets And Liabilities [Line Items]
 
 
Total Regulatory Liabilities
204,630 
193,424 
Taxes Refundable To Customers [Member]
 
 
Regulatory Assets And Liabilities [Line Items]
 
 
Total Regulatory Liabilities
95,739 
93,318 
Post-Retirement Benefit Costs [Member]
 
 
Regulatory Assets And Liabilities [Line Items]
 
 
Total Regulatory Liabilities
102,891 
67,204 
Amounts Payable To Customers [Member]
 
 
Regulatory Assets And Liabilities [Line Items]
 
 
Total Regulatory Liabilities
19,537 
Other [Member]
 
 
Regulatory Assets And Liabilities [Line Items]
 
 
Total Regulatory Liabilities
44,884 2
47,310 2
Total Long-Term Regulatory Liabilities
10,825 
32,585 
Non-Current Regulatory Liabilities [Member]
 
 
Regulatory Assets And Liabilities [Line Items]
 
 
Total Long-Term Regulatory Liabilities
414,085 
386,531 
Other Accruals and Current Liabilities [Member]
 
 
Regulatory Assets And Liabilities [Line Items]
 
 
Less: Amounts Included in Current and Accrued Liabilities
(34,059)
(14,725)
Pension Costs Asset [Member]
 
 
Regulatory Assets And Liabilities [Line Items]
 
 
Total Regulatory Assets
125,175 1 3
203,755 1 3
Post-Retirement Benefit Costs [Member]
 
 
Regulatory Assets And Liabilities [Line Items]
 
 
Total Regulatory Assets
13,886 1 3
74,802 1 3
Recoverable Future Taxes [Member]
 
 
Regulatory Assets And Liabilities [Line Items]
 
 
Total Regulatory Assets
181,363 1
177,261 1
Environmental Site Remediation Costs [Member]
 
 
Regulatory Assets And Liabilities [Line Items]
 
 
Total Regulatory Assets
19,665 1 3
23,392 1 3
Asset Retirement Obligations [Member]
 
 
Regulatory Assets And Liabilities [Line Items]
 
 
Total Regulatory Assets
12,764 1 3
12,490 1 3
Unamortized Debt Expense [Member]
 
 
Regulatory Assets And Liabilities [Line Items]
 
 
Total Regulatory Assets
1,159 1
1,688 1
Other [Member]
 
 
Regulatory Assets And Liabilities [Line Items]
 
 
Total Regulatory Assets
18,827 1 4
21,927 1 4
Total Long-Term Regulatory Assets
2,943 
6,311 
Long-Term Regulatory Assets [Member]
 
 
Regulatory Assets And Liabilities [Line Items]
 
 
Total Long-Term Regulatory Assets
356,955 1
499,699 1
Other Current Assets [Member]
 
 
Regulatory Assets And Liabilities [Line Items]
 
 
Less: Amounts Included in Other Current Assets
$ (15,884)
$ (15,616)
Income Taxes (Narrative) (Details) (USD $)
Sep. 30, 2017
Sep. 30, 2016
Income Taxes [Line Items]
 
 
Cumulative Effect of Adoption of Authoritative Guidance for Stock-Based Compensation
$ 31,900,000 
 
Taxes Refundable to Customers
95,739,000 
93,318,000 
Recoverable Future Taxes
181,363,000 
177,261,000 
Federal net operating loss, certain annual limitations
1,800,000 
 
Deferred Income Taxes [Member]
 
 
Income Taxes [Line Items]
 
 
Taxes Refundable to Customers
95,700,000 
93,300,000 
Recoverable Future Taxes
181,400,000 
177,300,000 
Regulatory liabilities
52,600,000 
52,600,000 
Regulatory assets
$ 99,400,000 
$ 94,200,000 
Income Taxes (Components Of Federal And State Income Taxes Included In The Consolidated Statements Of Income) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
Current Income Taxes [Abstract]
 
 
 
Federal
$ 32,034 
$ (6,658)
$ 25,064 
State
10,673 
20,903 
13,387 
Deferred Income Taxes [Abstract]
 
 
 
Federal
103,046 
(164,818)
(244,336)
State
14,929 
(81,976)
(113,251)
Income Tax Expense (Benefit)
160,682 
(232,549)
(319,136)
Deferred Investment Tax Credit
(173)
(348)
(414)
Total Income Taxes
160,509 
(232,897)
(319,550)
Presented as Follows [Abstract]
 
 
 
Other Income
(173)
(348)
(414)
Income Tax Expense (Benefit)
$ 160,682 
$ (232,549)
$ (319,136)
Income Taxes (Schedule Of Income Tax Reconciliation By Applying Federal Income Tax Rate) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
Income Tax Disclosure [Abstract]
 
 
 
U.S. Income (Loss) Before Income Taxes
$ 443,991 
$ (523,855)
$ (698,977)
Income Tax Expense (Benefit), Computed at U.S. Federal Statutory Rate of 35%
155,397 
(183,349)
(244,642)
State Income Taxes (Benefit)
16,641 
(39,697)
(64,912)
Federal Tax Credits
(6,679)
(3,262)
(732)
Miscellaneous
(4,850)
(6,589)
(9,264)
Total Income Taxes
$ 160,509 
$ (232,897)
$ (319,550)
Federal Statutory Rate
35.00% 
35.00% 
35.00% 
Income Taxes (Significant Components Of Deferred Tax Liabilities And Assets) (Details) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2017
Sep. 30, 2016
Deferred Tax Liabilities [Abstract]
 
 
Property, Plant and Equipment
$ 1,141,432 
$ 1,049,100 
Pension and Other Post-Retirement Benefit Costs
79,516 
151,903 
Unrealized Hedging Gains
19,127 
50,179 
Other
57,919 
55,457 
Total Deferred Tax Liabilities
1,297,994 
1,306,639 
Deferred Tax Assets [Abstract]
 
 
Pension and Other Post-Retirement Benefit Costs
(123,532)
(195,829)
Tax Loss and Credit Carryforwards
(200,344)
(194,875)
Other
(82,831)
(92,140)
Total Deferred Tax Assets
(406,707)
(482,844)
Total Net Deferred Income Taxes
$ 891,287 
$ 823,795 
Income Taxes (Reconciliation Of The Change In Unrecognized Tax Benefits) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
Income Tax Disclosure [Abstract]
 
 
 
Balance at Beginning of Year
$ 396 
$ 5,085 
$ 3,147 
Additions for Tax Positions of Prior Years
1,251 
396 
2,504 
Reductions for Tax Positions of Prior Years
(396)
(1,314)
(566)
Reductions Related to Settlements with Taxing Authorities
(3,771)
Balance at End of Year
$ 1,251 
$ 396 
$ 5,085 
Income Taxes Income Taxes (Summary of Operating Loss and Tax Credit Carryforwards) (Details) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2017
Federal [Member]
 
Operating Loss Carryforwards [Line Items]
 
Net operating loss
$ 184,289 
Alternative Minimum Tax Credit [Member]
 
Operating Loss Carryforwards [Line Items]
 
Tax Credit Carryforwards
81,683 
Research and Development Tax Credit Carryforward [Member]
 
Operating Loss Carryforwards [Line Items]
 
Tax Credit Carryforwards
5,694 
Enhanced Oil Recovery Credit [Member] |
Federal [Member]
 
Operating Loss Carryforwards [Line Items]
 
Tax Credit Carryforwards
10,502 
Pennsylvania [Member]
 
Operating Loss Carryforwards [Line Items]
 
Net operating loss
324,572 
California [Member]
 
Operating Loss Carryforwards [Line Items]
 
Net operating loss
169,723 
California [Member] |
Alternative Minimum Tax Credit [Member]
 
Operating Loss Carryforwards [Line Items]
 
Tax Credit Carryforwards
5,873 
California [Member] |
Enhanced Oil Recovery Credit [Member]
 
Operating Loss Carryforwards [Line Items]
 
Tax Credit Carryforwards
$ 5,061 
Capitalization And Short-Term Borrowings (Narrative) (Details) (USD $)
3 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended 12 Months Ended
Sep. 30, 2017
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
Sep. 30, 2017
Stock Options And SARs [Member]
Sep. 30, 2017
Stock Options [Member]
Sep. 30, 2016
Stock Options [Member]
Sep. 30, 2015
Stock Options [Member]
Sep. 30, 2017
Stock Appreciation Rights (SARs) [Member]
Sep. 30, 2016
Stock Appreciation Rights (SARs) [Member]
Sep. 30, 2015
Stock Appreciation Rights (SARs) [Member]
Sep. 30, 2017
Restricted Share Awards [Member]
Sep. 30, 2016
Restricted Share Awards [Member]
Sep. 30, 2015
Restricted Share Awards [Member]
Sep. 30, 2017
Non-Performance Based Restricted Stock Units (RSUs) [Member]
Sep. 30, 2016
Non-Performance Based Restricted Stock Units (RSUs) [Member]
Sep. 30, 2015
Non-Performance Based Restricted Stock Units (RSUs) [Member]
Sep. 30, 2017
Performance Shares [Member]
Sep. 30, 2016
Performance Shares [Member]
Sep. 30, 2015
Performance Shares [Member]
Sep. 30, 2017
Restricted Stock Units (RSUs) [Member]
Sep. 18, 2017
3.95% Notes Due September 15, 2027 [Member]
Sep. 18, 2017
3.95% Notes Due September 15, 2027 [Member]
Sep. 30, 2017
6.50% Notes Due April 2018 [Member]
Sep. 30, 2017
Indenture From 1974 [Member]
Sep. 30, 2017
Commercial Paper [Member]
Sep. 30, 2017
Board Of Directors [Member]
Sep. 30, 2017
Third Amended & Restated Credit Agreement [Member]
Sep. 30, 2017
364-Day Revolving Credit Facility [Member]
Sep. 30, 2017
Last Day of Fiscal Quarter Through September 30, 2017 [Member]
Sep. 30, 2017
Last Day of Fiscal Quarter October 1, 2017 through December 5, 2019 [Member]
Sep. 30, 2017
2018 [Member]
Non-Performance Based Restricted Stock Units (RSUs) [Member]
Sep. 30, 2017
2018 [Member]
Performance Shares [Member]
Sep. 30, 2017
2019 [Member]
Non-Performance Based Restricted Stock Units (RSUs) [Member]
Sep. 30, 2017
2019 [Member]
Performance Shares [Member]
Sep. 30, 2017
2020 [Member]
Non-Performance Based Restricted Stock Units (RSUs) [Member]
Sep. 30, 2017
2020 [Member]
Performance Shares [Member]
Sep. 30, 2017
2021 [Member]
Restricted Share Awards [Member]
Sep. 30, 2017
2021 [Member]
Non-Performance Based Restricted Stock Units (RSUs) [Member]
Sep. 30, 2017
2022 [Member]
Non-Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan
 
180,247 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common stock issued for 401(k) plans
 
103,602 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common stock shares issued due to stock option and SARs exercises
 
(19,000)
 
 
45,912 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common stock issued
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
43,484 
 
 
80,530 
 
 
 
 
 
24,028 
 
 
 
 
 
 
 
 
 
 
 
 
 
Shares tendered
 
53,564 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of voting power
 
10.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of assets or earning power that are sold or transferred
50.00% 
50.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Equity redemption price per share
 
$ 0.005 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Voting power percentage to redeem rights
 
75.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Rights expiration date
 
Jul. 31, 2018 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Share-Based Payment Expense
 
$ 10,800,000 
$ 4,800,000 
$ 2,100,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Tax benefit related to stock-based compensation expense
 
4,400,000 
1,900,000 
900,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Capitalized stock-based compensation costs
 
100,000 
100,000 
100,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Tax benefit from stock-based compensation exercises and vestings
 
500,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Options, exercises in period, total intrinsic value
 
 
 
 
 
300,000 
4,100,000 
5,100,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proceeds from Stock Options Exercised
 
 
 
 
 
800,000 
8,000,000 
5,600,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of Shares Granted
 
 
 
 
 
 
 
 
87,143 
101,943 
88,899 
184,148 
309,996 
107,044 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Weighted Average Fair Value per Award Granted
 
 
 
 
 
 
 
 
 
 
 
$ 0.00 
 
 
$ 52.13 
$ 35.89 
$ 64.04 
$ 56.39 
$ 30.71 
$ 65.26 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total intrinsic value of SAR's exercised
 
 
 
 
 
 
 
 
1,600,000 
400,000 
2,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of Awards Vested
 
 
 
 
 
 
 
 
5,000 
113,082 
157,386 
 
 
80,530 
 
 
43,484 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Equity instruments other than options, vested in period, total fair value
 
 
 
 
 
 
 
 
100,000 
1,200,000 
1,700,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Unrecognized compensation expense
 
 
 
 
 
 
 
 
 
 
 
300,000 
 
 
4,700,000 
 
 
10,100,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Unrecognized compensation expense recognized weighted average period
 
 
 
 
 
 
 
 
 
 
 
3 years 1 month 13 days 
 
 
2 years 2 months 13 days 
 
 
1 year 8 months 10 days 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Non-vested stock-based compensation lapse
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
73,819 
88,132 
65,265 
255,468 
52,641 
184,148 
20,000 
27,976 
13,498 
Carrying Amount
2,383,681,000 
2,383,681,000 
2,086,252,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
98,700,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term debt, face value
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
300,000,000 
300,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of Long-Term Debt issued under 1974 Indenture
 
4.10% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term debt, interest rate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3.95% 
6.50% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net proceeds from issuance of long-term debt
 
295,151,000 
444,635,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
295,200,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Principal amounts of long-term debt maturing in 2018
300,000,000 
300,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Principal amounts of long-term debt maturing in 2019
250,000,000 
250,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Principal amounts of long-term debt maturing in 2020
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Principal amounts of long-term debt maturing in 2021
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Principal amounts of long-term debt maturing in 2022
500,000,000 
500,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Principal amounts of long-term debt maturing after 2022
1,349,000,000 
1,349,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commercial paper available
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
500,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Maximum Borrowing Capacity
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
750,000,000.0 
500,000,000 
 
 
 
 
 
 
 
 
 
 
 
Commercial paper, outstanding
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Expiration Date
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sep. 30, 2017 
Dec. 05, 2019 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Term Start Date
 
Oct. 01, 2017 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Short-term notes payable outstanding
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Committed credit facility debt to capitalization ratio
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.675 
0.65 
 
 
 
 
 
 
 
 
 
Debt to capitalization ratio
 
0.58 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Additional borrowing
1,150,000,000 
1,150,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum debt increase under existing indenture covenants
126,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Aggregated indebtedness
 
40,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Preferred stock, shares authorized
10,000,000 
10,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Preferred stock par value
$ 1 
$ 1 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Committed credit facility, outstanding amount
$ 0 
$ 0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Capitalization And Short-Term Borrowings (Summary Of Changes In Common Stock Equity) (Details) (USD $)
In Thousands, except Share data, unless otherwise specified
3 Months Ended 12 Months Ended
Sep. 30, 2017
Jun. 30, 2017
Mar. 31, 2017
Dec. 31, 2016
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Dec. 31, 2015
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
Schedule of Capitalization [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual Term
 
 
 
 
 
 
 
 
0 years 0 months 0 days 
 
 
Beginning balance (shares)
 
 
 
85,118,886 
 
 
 
 
85,118,886 
 
 
Beginning balance
 
 
 
$ 771,164 
 
 
 
 
$ 771,164 
 
 
Balance at Beginning of Year
 
 
 
676,361 
 
 
 
1,103,200 
676,361 
1,103,200 
1,614,361 
Beginning balance
 
 
 
(5,640)
 
 
 
93,372 
(5,640)
93,372 
 
Net Income (Loss) Available for Common Stock
45,577 
59,714 
89,283 
88,908 
37,553 1
8,286 2
(147,688)3
(189,109)4
283,482 
(290,958)
(379,427)
Dividends Declared on Common Stock
 
 
 
 
 
 
 
 
(140,090)
(135,881)
(131,734)
Cumulative Effect of Adoption of Authoritative Guidance for Stock-Based Compensation
31,900 
 
 
 
 
 
 
 
31,900 
 
 
Other Comprehensive Income (Loss), Net of Tax
 
 
 
 
 
 
 
 
(24,483)
(99,012)
97,351 
Share-Based Payment Expense
 
 
 
 
 
 
 
 
10,800 
4,800 
2,100 
Ending balance (Shares)
85,543,125 
 
 
 
85,118,886 
 
 
 
85,543,125 
85,118,886 
 
Ending balance
796,646 
 
 
 
771,164 
 
 
 
796,646 
771,164 
 
Balance at End of Year
851,669 
 
 
 
676,361 
 
 
 
851,669 
676,361 
1,103,200 
Ending balance
(30,123)
 
 
 
(5,640)
 
 
 
(30,123)
(5,640)
93,372 
Dividend per share
 
 
 
 
 
 
 
 
$ 1.64 
$ 1.60 
$ 1.56 
Tax benefit related to stock-based compensation recorded to Paid in Capital
 
 
 
 
 
 
 
 
 
1,868 
9,064 
Accumulated earnings free from limitations
707,500 
 
 
 
 
 
 
 
707,500 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term
 
 
 
 
 
 
 
 
0 years 0 months 0 days 
 
 
Common Stock [Member]
 
 
 
 
 
 
 
 
 
 
 
Schedule of Capitalization [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Beginning balance (shares)
 
 
 
85,119,000 
 
 
 
84,594,000 
85,119,000 
84,594,000 
84,157,000 
Beginning balance (value)
 
 
 
85,119 
 
 
 
84,594 
85,119 
84,594 
84,157 
Common Stock Issued Under Stock and Benefit Plans (Shares)
 
 
 
 
 
 
 
 
424,000 5
525,000 5
437,000 5
Common Stock Issued Under Stock and Benefit Plans (Value)
 
 
 
 
 
 
 
 
424 5
525 5
437 5
Ending balance (Shares)
85,543,000 
 
 
 
85,119,000 
 
 
 
85,543,000 
85,119,000 
84,594,000 
Ending balance (Value)
85,543 
 
 
 
85,119 
 
 
 
85,543 
85,119 
84,594 
Paid In Capital [Member]
 
 
 
 
 
 
 
 
 
 
 
Schedule of Capitalization [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Beginning balance
 
 
 
771,164 
 
 
 
744,274 
771,164 
744,274 
716,144 
Share-Based Payment Expense
 
 
 
 
 
 
 
 
10,902 6
4,843 6
2,207 6
Common Stock Issued Under Stock and Benefit Plans (Value)
 
 
 
 
 
 
 
 
14,580 5
22,047 5
25,923 5
Ending balance
796,646 
 
 
 
771,164 
 
 
 
796,646 
771,164 
744,274 
Earnings Reinvested In The Business [Member]
 
 
 
 
 
 
 
 
 
 
 
Schedule of Capitalization [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Balance at Beginning of Year
 
 
 
676,361 
 
 
 
1,103,200 
676,361 
1,103,200 
1,614,361 
Net Income (Loss) Available for Common Stock
 
 
 
 
 
 
 
 
283,482 
(290,958)
(379,427)
Dividends Declared on Common Stock
 
 
 
 
 
 
 
 
(140,090)
(135,881)
(131,734)
Cumulative Effect of Adoption of Authoritative Guidance for Stock-Based Compensation
31,916 
 
 
 
 
 
 
 
31,916 
 
 
Balance at End of Year
851,669 7
 
 
 
676,361 
 
 
 
851,669 7
676,361 
1,103,200 
Accumulated Other Comprehensive Income (Loss) [Member]
 
 
 
 
 
 
 
 
 
 
 
Schedule of Capitalization [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Beginning balance
 
 
 
(5,640)
 
 
 
93,372 
(5,640)
93,372 
(3,979)
Other Comprehensive Income (Loss), Net of Tax
 
 
 
 
 
 
 
 
(24,483)
(99,012)
97,351 
Ending balance
$ (30,123)
 
 
 
$ (5,640)
 
 
 
$ (30,123)
$ (5,640)
$ 93,372 
Capitalization And Short-Term Borrowings (Schedule Of Share-Based Compensation For Stock Options And Share Awards) (Details) (USD $)
In Thousands, except Share data, unless otherwise specified
12 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
Schedule of Capitalization [Line Items]
 
 
 
Number of Shares Outstanding, Beginning of Year
19,000 
 
 
Number of Shares Granted
 
 
Number of Shares Exercised
(19,000)
 
 
Number of Shares Forfeited
 
 
Number of Shares Outstanding, End of Year
 
 
Number of Option shares exercisable
 
 
Number of Shares Subject to Option, Option shares available for future grant
2,182,243 1
 
 
Weighted Average Exercise Price, Outstanding Beginning of Year
$ 39.48 
 
 
Weighted Average Exercise Price, Granted
$ 0.00 
 
 
Weighted Average Exercise Price, Exercised
$ 39.48 
 
 
Weighted Average Exercise Price, Forfeited
$ 0.00 
 
 
Weighted Average Exercise Price, Outstanding End of Year
$ 0.00 
 
 
Weighted Average Exercise Price, Option shares exercisable
$ 0.00 
 
 
Weighted Average Remaining Contractual Life, Outstanding
0 years 0 months 0 days 
 
 
Weighted Average Remaining Contractual Life, Option shares exercisable
0 years 0 months 0 days 
 
 
Aggregate Intrinsic Value Outstanding
$ 0 
 
 
Aggregate Intrinsic Value, Option Shares exercisable
 
 
Performance Shares [Member]
 
 
 
Schedule of Capitalization [Line Items]
 
 
 
Number of Shares Outstanding, Beginning of Year
438,234 
 
 
Number of Shares Granted
184,148 
309,996 
107,044 
Number of Awards Vested
(43,484)
 
 
Number of Shares Forfeited
(51,150)
 
 
Number of Shares Outstanding, End of Year
527,748 
438,234 
 
Weighted Average Fair Value per Award, Beginning of Year
$ 44.98 
 
 
Weighted Average Fair Value per Award Granted
$ 56.39 
$ 30.71 
$ 65.26 
Weighted Average Fair Value per Award Vested
$ 69.13 
 
 
Weighted Average Fair Value per Award Forfeited
$ 60.74 
 
 
Weighted Average Fair Value per Award, End of Year
$ 45.44 
$ 44.98 
 
Stock Appreciation Rights (SARs) [Member]
 
 
 
Schedule of Capitalization [Line Items]
 
 
 
Number of Shares Outstanding, Beginning of Year
1,590,988 
 
 
Number of Shares Granted
Number of Shares Exercised
(82,077)
 
 
Number of Awards Vested
(5,000)
(113,082)
(157,386)
Number of Shares Forfeited
 
 
Number of Shares Expired
(3,000)
 
 
Number of Shares Outstanding, End of Year
1,505,911 
1,590,988 
 
Number of SARs exercisable
1,505,911 
 
 
Weighted Average Exercise Price, Outstanding Beginning of Year
$ 48.19 
 
 
Weighted Average Exercise Price, Granted
$ 0.00 
 
 
Weighted Average Exercise Price, Exercised
$ 39.77 
 
 
Weighted Average Exercise Price, Forfeited
$ 0.00 
 
 
Weighted Average Exercise Price, Expired
$ 52.10 
 
 
Weighted Average Exercise Price, Outstanding End of Year
$ 48.64 
$ 48.19 
 
Weighted Average Exercise Price, SARs exercisable
$ 48.64 
 
 
Weighted Average Remaining Contractual Life, Outstanding
2 years 6 months 6 days 
 
 
Weighted Average Remaining Contractual Life, SARs exercisable
2 years 6 months 6 days 
 
 
Aggregate Intrinsic Value Outstanding
13,144 
 
 
Aggregate Intrinsic Value, SARs exercisable
$ 13,144 
 
 
Capitalization And Short-Term Borrowings (Schedule Of Share-Based Compensation For Restricted Stock Units) (Details) (USD $)
12 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
Restricted Share Awards [Member]
 
 
 
Schedule of Capitalization [Line Items]
 
 
 
Number of Shares Outstanding, Beginning of Year
20,000 
 
 
Number of Shares Granted
Number of Awards Vested
 
 
Number of Shares Forfeited
 
 
Number of Shares Outstanding, End of Year
20,000 
20,000 
 
Weighted Average Fair Value per Award, Beginning of Year
$ 47.46 
 
 
Weighted Average Fair Value per Award Granted
$ 0.00 
 
 
Weighted Average Fair Value per Award Vested
$ 0.00 
 
 
Weighted Average Fair Value per Award Forfeited
$ 0.00 
 
 
Weighted Average Fair Value per Award, End of Year
$ 47.46 
$ 47.46 
 
Non-Performance Based Restricted Stock Units (RSUs) [Member]
 
 
 
Schedule of Capitalization [Line Items]
 
 
 
Number of Shares Outstanding, Beginning of Year
239,151 
 
 
Number of Shares Granted
87,143 
101,943 
88,899 
Number of Awards Vested
(80,530)
 
 
Number of Shares Forfeited
(12,565)
 
 
Number of Shares Outstanding, End of Year
233,199 
239,151 
 
Weighted Average Fair Value per Award, Beginning of Year
$ 49.67 
 
 
Weighted Average Fair Value per Award Granted
$ 52.13 
$ 35.89 
$ 64.04 
Weighted Average Fair Value per Award Vested
$ 53.38 
 
 
Weighted Average Fair Value per Award Forfeited
$ 53.75 
 
 
Weighted Average Fair Value per Award, End of Year
$ 48.99 
$ 49.67 
 
Capitalization And Short-Term Borrowings (Weighted Average Assumptions Used In Estimating Fair Value) (Details) (Performance Shares [Member])
12 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
Performance Shares [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
Risk Free Interest Rate
1.54% 
1.26% 
1.01% 
Remaining Term at Date of Grant (Years)
2 years 9 months 14 days 
2 years 9 months 14 days 
2 years 9 months 12 days 
Expected Volatility Rate
22.60% 
20.50% 
20.10% 
Capitalization And Short-Term Borrowings (Schedule Of Long-Term Debt) (Details) (USD $)
12 Months Ended 12 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2017
6.50% Notes Due April 2018 [Member]
Sep. 30, 2017
3.95% Notes Due September 15, 2027 [Member]
Sep. 18, 2017
3.95% Notes Due September 15, 2027 [Member]
Sep. 30, 2017
7.4% Due March 2023 To June 2025 [Member]
Sep. 30, 2016
7.4% Due March 2023 To June 2025 [Member]
Sep. 30, 2017
3.75% To 8.75% Due April 2018 To September 2027 [Member]
Sep. 30, 2016
3.75% To 8.75% Due April 2018 To September 2027 [Member]
Sep. 30, 2017
Minimum [Member]
3.75% To 8.75% Due April 2018 To September 2027 [Member]
Sep. 30, 2016
Minimum [Member]
3.75% To 8.75% Due April 2018 To September 2027 [Member]
Sep. 30, 2017
Maximum [Member]
3.75% To 8.75% Due April 2018 To September 2027 [Member]
Sep. 30, 2016
Maximum [Member]
3.75% To 8.75% Due April 2018 To September 2027 [Member]
Debt Instrument [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
Medium-Term Notes
 
 
 
 
 
$ 99,000,000 1
$ 99,000,000 1
 
 
 
 
 
 
Notes
 
 
 
 
 
 
 
2,300,000,000 1 2 3
2,000,000,000 1 2 3
 
 
 
 
Total Long-Term Debt
2,399,000,000 
2,099,000,000 
 
 
 
 
 
 
 
 
 
 
 
Less Unamortized Discount and Debt Issuance Costs
15,319,000 
12,748,000 
 
 
 
 
 
 
 
 
 
 
 
Less Current Portion
300,000,000 4
4
 
 
 
 
 
 
 
 
 
 
 
Long-term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs
2,083,681,000 
2,086,252,000 
 
 
 
 
 
 
 
 
 
 
 
Long-term debt, face value
 
 
300,000,000 
 
300,000,000 
 
 
 
 
 
 
 
 
Long-term debt, interest rate
 
 
6.50% 
 
3.95% 
7.40% 
7.40% 
 
 
3.75% 
3.75% 
8.75% 
8.75% 
Percentage of principal amount
 
 
 
 
 
 
 
101.00% 
101.00% 
 
 
 
 
Debt Instrument redeemed
$ 307,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum interest rate adjustment
 
 
 
2.00% 
 
 
 
 
 
 
 
 
 
Fair Value Measurements (Narrative) (Details) (USD $)
12 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Hedging collateral deposits
$ 1,741,000 1
$ 1,484,000 1
Level 1 or Level 2 Transfers
Derivative Financial Instruments [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Level 3 Fair Value
Level 1 or Level 2 Transfers
Sales of Derivative Financial Instruments
 
Purchases of Derivative Financial Instruments
Fair Value, Inputs, Level 1 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Hedging collateral deposits
1,741,000 
1,484,000 
Fair Value, Inputs, Level 1 [Member] |
Futures [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Hedging collateral deposits
1,700,000 
1,500,000 
Fair Value, Inputs, Level 3 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Hedging collateral deposits
$ 0 
$ 0 
Fair Value Measurements (Recurring Fair Value Measures Of Assets And Liabilities) (Details) (USD $)
Sep. 30, 2017
Sep. 30, 2016
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Cash Equivalents - Money Market Mutual Funds
$ 527,978,000 1
$ 113,407,000 1
Hedging Collateral Deposits
1,741,000 1
1,484,000 1
Total Assets
651,740,000 1
299,650,000 1
Total Liabilities
1,103,000 1
1,462,000 1
Total Net Assets/(Liabilities)
650,637,000 1
298,188,000 1
Commodity Futures Contracts - Gas [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Derivative Asset
520,000 1
347,000 1
Derivative Liability
1
1
Over Counter Swaps Gas And Oil [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Derivative Asset
34,771,000 1
115,794,000 1
Derivative Liability
1,103,000 1
1,462,000 1
Foreign Currency Contracts [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Derivative Asset
820,000 1
(2,337,000)1
Derivative Liability
1
1
Balanced Equity Mutual Fund [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Other Investments
37,033,000 1
36,658,000 1
Fixed Income Mutual Fund [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Other Investments
45,727,000 1
31,395,000 1
Common Stock - Financial Services Industry [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Other Investments
3,150,000 1
2,902,000 1
Fair Value, Inputs, Level 1 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Cash Equivalents - Money Market Mutual Funds
527,978,000 
113,407,000 
Hedging Collateral Deposits
1,741,000 
1,484,000 
Total Assets
617,112,000 
188,469,000 
Total Liabilities
963,000 
2,276,000 
Total Net Assets/(Liabilities)
616,149,000 
186,193,000 
Fair Value, Inputs, Level 1 [Member] |
Commodity Futures Contracts - Gas [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Derivative Asset
1,483,000 
2,623,000 
Derivative Liability
963,000 
2,276,000 
Fair Value, Inputs, Level 1 [Member] |
Over Counter Swaps Gas And Oil [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Derivative Asset
Derivative Liability
Fair Value, Inputs, Level 1 [Member] |
Foreign Currency Contracts [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Derivative Asset
Derivative Liability
Fair Value, Inputs, Level 1 [Member] |
Balanced Equity Mutual Fund [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Other Investments
37,033,000 
36,658,000 
Fair Value, Inputs, Level 1 [Member] |
Fixed Income Mutual Fund [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Other Investments
45,727,000 
31,395,000 
Fair Value, Inputs, Level 1 [Member] |
Common Stock - Financial Services Industry [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Other Investments
3,150,000 
2,902,000 
Fair Value, Inputs, Level 2 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Cash Equivalents - Money Market Mutual Funds
Hedging Collateral Deposits
Total Assets
40,204,000 
119,654,000 
Total Liabilities
5,716,000 
7,659,000 
Total Net Assets/(Liabilities)
34,488,000 
111,995,000 
Fair Value, Inputs, Level 2 [Member] |
Commodity Futures Contracts - Gas [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Derivative Asset
Derivative Liability
Fair Value, Inputs, Level 2 [Member] |
Over Counter Swaps Gas And Oil [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Derivative Asset
38,977,000 
119,654,000 
Derivative Liability
5,309,000 
5,322,000 
Fair Value, Inputs, Level 2 [Member] |
Foreign Currency Contracts [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Derivative Asset
1,227,000 
Derivative Liability
407,000 
2,337,000 
Fair Value, Inputs, Level 2 [Member] |
Balanced Equity Mutual Fund [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Other Investments
Fair Value, Inputs, Level 2 [Member] |
Fixed Income Mutual Fund [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Other Investments
Fair Value, Inputs, Level 2 [Member] |
Common Stock - Financial Services Industry [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Other Investments
Fair Value, Inputs, Level 3 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Cash Equivalents - Money Market Mutual Funds
Hedging Collateral Deposits
Total Assets
Total Liabilities
Total Net Assets/(Liabilities)
Fair Value, Inputs, Level 3 [Member] |
Commodity Futures Contracts - Gas [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Derivative Asset
Derivative Liability
Fair Value, Inputs, Level 3 [Member] |
Over Counter Swaps Gas And Oil [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Derivative Asset
Derivative Liability
Fair Value, Inputs, Level 3 [Member] |
Foreign Currency Contracts [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Derivative Asset
Derivative Liability
Fair Value, Inputs, Level 3 [Member] |
Balanced Equity Mutual Fund [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Other Investments
Fair Value, Inputs, Level 3 [Member] |
Fixed Income Mutual Fund [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Other Investments
Fair Value, Inputs, Level 3 [Member] |
Common Stock - Financial Services Industry [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Other Investments
Netting Adjustments [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Cash Equivalents - Money Market Mutual Funds
1
1
Hedging Collateral Deposits
1
1
Total Assets
(5,576,000)1
(8,473,000)1
Total Liabilities
(5,576,000)1
(8,473,000)1
Total Net Assets/(Liabilities)
1
1
Netting Adjustments [Member] |
Commodity Futures Contracts - Gas [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Derivative Asset
(963,000)1
(2,276,000)1
Derivative Liability
(963,000)1
(2,276,000)1
Netting Adjustments [Member] |
Over Counter Swaps Gas And Oil [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Derivative Asset
(4,206,000)1
(3,860,000)1
Derivative Liability
(4,206,000)1
(3,860,000)1
Netting Adjustments [Member] |
Foreign Currency Contracts [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Derivative Asset
(407,000)1
(2,337,000)1
Derivative Liability
(407,000)1
(2,337,000)1
Netting Adjustments [Member] |
Balanced Equity Mutual Fund [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Other Investments
1
1
Netting Adjustments [Member] |
Fixed Income Mutual Fund [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Other Investments
1
1
Netting Adjustments [Member] |
Common Stock - Financial Services Industry [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
 
 
Other Investments
$ 0 1
$ 0 1
Financial Instruments (Narrative) (Details) (USD $)
12 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Derivative Instruments, Gain (Loss) [Line Items]
 
 
Cash Surrender Value of Life Insurance
$ 39,400,000 
$ 39,700,000 
Net hedging gains (losses) in accumulated other comprehensive income (loss)
35,500,000 
 
After tax net hedging gains (losses) in accumulated other comprehensive income (loss)
20,800,000 
 
Pre-tax Net hedging gains (losses) reclassified within twelve months
18,000,000 
 
After tax Net hedging gains (losses) reclassified within twelve months
10,600,000 
 
Fair market value of derivative asset with a credit-risk related contingency
26,000,000 
 
Hedging collateral deposits
1,741,000 1
1,484,000 1
Equity Mutual Fund [Member]
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
Fair value
37,000,000 
36,700,000 
Gross unrealized gain
9,900,000 
7,900,000 
Fixed Income Mutual Fund [Member]
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
Fair value
45,700,000 
31,400,000 
Gross unrealized loss
100,000 
 
Gross unrealized gain
 
100,000 
Insurance Company Stock [Member]
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
Fair value
3,200,000 
2,900,000 
Gross unrealized gain
2,200,000 
1,600,000 
Foreign Currency Contracts [Member]
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
Derivative, Notional Amount
89,200,000 
 
Fair Value Hedges Mmcf [Member] |
Energy Marketing [Member]
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
Nonmonetary notional amount of price risk fair value hedge derivatives, natural gas
17,500 
 
Exchange-Traded Futures Contracts [Member]
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
Hedging collateral deposits
1,700,000 
 
Fixed Price Sales Commitments MMCf [Member] |
Energy Marketing [Member]
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
Nonmonetary notional amount of price risk fair value hedge derivatives, natural gas
16,400 
 
Fixed Price Commitments Related To Withdrawal Of Storage Gas MMCf [Member] |
Energy Marketing [Member]
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
Nonmonetary notional amount of price risk fair value hedge derivatives, natural gas
1,100 
 
Over the Counter Swaps and Foreign Currency Forward Contracts [Member]
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
Number of counterparties in which the company holds over-the-counter swap positions
17 
 
Number of counterparties in net gain position
16 
 
Credit risk exposure per counterparty
2,200,000 
 
Maximum credit risk exposure per counterparty
6,000,000 
 
Collateral Received from Counterparties by the Company
 
Hedging collateral deposits
$ 0 
 
Over the Counter Swaps and Foreign Currency Forward Contracts [Member] |
Credit Risk Related Contingency Feature [Member]
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
Number of counterparties with a common credit-risk related contingency
14 
 
Cash Flow Hedges Short Position [Member] |
Natural Gas MMCf [Member]
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
Nonmonetary notional amount of price risk cash flow hedge derivatives, natural gas
114,300 
 
Cash Flow Hedges Short Position [Member] |
Crude Oil Bbls [Member]
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
Nonmonetary notional amount of price risk cash flow hedge derivative, crude oil
3,459,000 
 
Cash Flow Hedges Long Position [Member] |
Natural Gas MMCf [Member]
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
Nonmonetary notional amount of price risk cash flow hedge derivatives, natural gas
1,000 
 
Financial Instruments (Long-Term Debt) (Details) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2017
Sep. 30, 2016
Financial Instruments, Owned, at Fair Value [Abstract]
 
 
Carrying Amount
$ 2,383,681 
$ 2,086,252 
Fair Value
$ 2,523,639 
$ 2,255,562 
Financial Instruments (Schedule Of Derivatives Financial Instruments Designated And Qualifying As Cash Flow Hedges On The Statements Of Financial Performance) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) (Effective Portion)
$ 5,347 
$ 60,493 
$ 381,018 
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion)
81,605 
220,919 
 
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
(100)
392 
 
Foreign Currency Contracts [Member] |
Operation and Maintenance Expense [Member]
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) (Effective Portion)
2,700 
194 
 
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion)
(457)
(424)
 
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
 
Commodity Contracts [Member] |
Operating Revenues [Member]
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) (Effective Portion)
2,811 
58,714 
 
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion)
83,983 
216,823 
 
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
(100)
392 
 
Commodity Contracts [Member] |
Purchased Gas [Member]
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) (Effective Portion)
(164)
1,585 
 
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion)
(1,921)
4,520 
 
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
$ 0 
$ 0 
 
Financial Instruments (Schedule Of Derivatives And Hedged Items In Fair Value Hedging Relationships) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Sep. 30, 2017
Derivative Instruments, Gain (Loss) [Line Items]
 
Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income
$ 2,119 
Amount of Gain or (Loss) on Hedged Item Recognized in the Consolidated Statement of Income
(2,119)
Operating Revenues [Member]
 
Derivative Instruments, Gain (Loss) [Line Items]
 
Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income
1,655 
Amount of Gain or (Loss) on Hedged Item Recognized in the Consolidated Statement of Income
(1,655)
Purchased Gas [Member]
 
Derivative Instruments, Gain (Loss) [Line Items]
 
Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income
464 
Amount of Gain or (Loss) on Hedged Item Recognized in the Consolidated Statement of Income
$ (464)
Retirement Plan And Other Post-Retirement Benefits (Narrative) (Details) (USD $)
12 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
Sep. 30, 2014
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Increase to accumulated other comprehensive income
$ 44,731,000 
$ 171,586,000 
$ (169,919,000)
 
Expected future benefit payments in year one
64,400,000 
 
 
 
Expected future benefit payments in year two
65,000,000 
 
 
 
Expected future benefit payments in year three
65,400,000 
 
 
 
Expected future benefit payments in year four
65,800,000 
 
 
 
Expected future benefit payments in year five
66,200,000 
 
 
 
Expected future benefit payments in five years thereafter
331,100,000 
 
 
 
Effect of one percentage point increase on accumulated postretirement benefit obligation
57,900,000 
 
 
 
Effect of one percentage point increase on service and interest cost components
3,300,000 
 
 
 
Effect of one percentage point decrease on accumulated postretirement benefit obligation
48,500,000 
 
 
 
Effect of one percentage point decrease on service and interest cost components
2,700,000 
 
 
 
Benefit assets transferred
 
 
Benefit assets transferred in/out of Level 3
 
 
Non-Qualified Benefit Plans [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Net periodic benefit cost
7,600,000 
7,500,000 
7,000,000 
 
Accumulated benefit obligation
72,500,000 
72,400,000 
66,000,000 
 
Benefit obligation
88,900,000 
91,700,000 
85,800,000 
 
Discount rate
3.22% 
2.80% 
3.50% 
 
Rate of compensation increase
7.75% 
7.75% 
7.75% 
 
Tax-Deferred Savings Plans [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Costs Recognized
5,900,000 
5,900,000 
5,800,000 
 
Retirement Savings Account [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Costs Recognized
2,900,000 
2,600,000 
2,300,000 
 
Other Than Veba Trust And 401(h) Accounts [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Employer Contributions
100,000 
 
 
 
Non-Qualified Benefit Plans, Other Post-Retirement Benefit Plan And Retirement Plan [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Decrease in other regulatory assets
163,300,000 
 
 
 
Increase to accumulated other comprehensive income
29,100,000 
 
 
 
Retirement Plan [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Net periodic benefit cost
34,848,000 
32,095,000 
37,700,000 
 
Accumulated benefit obligation
1,010,179,000 
1,039,408,000 
968,984,000 
 
Benefit obligation
1,054,826,000 
1,097,421,000 
1,026,190,000 
999,499,000 
Discount rate
3.77% 
3.60% 
4.25% 
 
Rate of compensation increase
4.70% 
4.70% 
4.75% 
 
Employer Contributions
17,146,000 
7,000,000 
36,200,000 
 
Expected long term rate of return on plan assets
7.00% 
7.25% 
7.50% 
 
Other Post-Retirement Benefit Plans [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Net periodic benefit cost
14,092,000 
12,923,000 
10,446,000 
 
Benefit obligation
462,619,000 
526,138,000 
464,987,000 
465,583,000 
Discount rate
3.81% 
3.70% 
4.50% 
 
Rate of compensation increase
4.70% 
4.70% 
4.75% 
 
Employer Contributions
3,853,000 
2,839,000 
2,161,000 
 
Expected future benefit payments in year one
26,483,000 
 
 
 
Expected future benefit payments in year two
27,456,000 
 
 
 
Expected future benefit payments in year three
28,359,000 
 
 
 
Expected future benefit payments in year four
29,173,000 
 
 
 
Expected future benefit payments in year five
29,757,000 
 
 
 
Expected future benefit payments in five years thereafter
152,957,000 
 
 
 
Expected long term rate of return on plan assets
6.50% 
6.75% 
7.00% 
 
VEBA Trusts [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Employer Contributions
3,800,000 
 
 
 
Other Actuarial Experience [Member] |
Retirement Plan [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Increase (decrease) in benefit obligation
(3,600,000)
 
 
 
Other Actuarial Experience [Member] |
Other Post-Retirement Benefit Plans [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Increase (decrease) in benefit obligation
(50,300,000)
11,000,000 
12,800,000 
 
Mortality Assumption Change [Member] |
Retirement Plan [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Increase (decrease) in benefit obligation
 
 
24,200,000 
 
Mortality Improvement Projection Scale [Member] |
Retirement Plan [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Increase (decrease) in benefit obligation
(8,300,000)
 
 
 
Mortality Improvement Projection Scale [Member] |
Other Post-Retirement Benefit Plans [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Increase (decrease) in benefit obligation
(5,700,000)
 
 
 
Discount Rate Change [Member] |
Retirement Plan [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Increase (decrease) in benefit obligation
(20,500,000)
78,500,000 
 
 
Discount Rate Change [Member] |
Other Post-Retirement Benefit Plans [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Increase (decrease) in benefit obligation
(6,200,000)
49,400,000 
(14,300,000)
 
Effective Fiscal 2018 [Member] |
Retirement Plan [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Expected long term rate of return on plan assets
7.00% 
 
 
 
Effective Fiscal 2018 [Member] |
Other Post-Retirement Benefit Plans [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Expected long term rate of return on plan assets
6.25% 
 
 
 
Minimum [Member] |
Retirement Plan [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Estimated future employer contributions in next fiscal year
15,000,000 
 
 
 
Minimum [Member] |
VEBA Trusts [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Estimated future employer contributions in next fiscal year
2,500,000 
 
 
 
Minimum [Member] |
Equity Securities [Member] |
Retirement Plan and Veba Trusts And 401H Accounts [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Target Allocation
40.00% 
 
 
 
Minimum [Member] |
Fixed Income Securities [Member] |
Retirement Plan and Veba Trusts And 401H Accounts [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Target Allocation
40.00% 
 
 
 
Minimum [Member] |
Other Securities [Member] |
Retirement Plan and Veba Trusts And 401H Accounts [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Target Allocation
0.00% 
 
 
 
Maximum [Member] |
Retirement Plan [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Estimated future employer contributions in next fiscal year
40,000,000 
 
 
 
Maximum [Member] |
VEBA Trusts [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Estimated future employer contributions in next fiscal year
4,000,000 
 
 
 
Maximum [Member] |
Equity Securities [Member] |
Retirement Plan and Veba Trusts And 401H Accounts [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Target Allocation
60.00% 
 
 
 
Maximum [Member] |
Fixed Income Securities [Member] |
Retirement Plan and Veba Trusts And 401H Accounts [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Target Allocation
60.00% 
 
 
 
Maximum [Member] |
Other Securities [Member] |
Retirement Plan and Veba Trusts And 401H Accounts [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Target Allocation
15.00% 
 
 
 
Other Accruals And Current Liabilities [Member] |
Non-Qualified Benefit Plans [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Benefit obligation
14,100,000 
9,800,000 
4,500,000 
 
Non-Current [Member] |
Non-Qualified Benefit Plans [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Benefit obligation
$ 74,800,000 
$ 81,900,000 
$ 81,300,000 
 
Retirement Plan And Other Post-Retirement Benefits (Schedule Of Benefit Obligations, Plan Assets And Funded Status) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Non-Current Assets
$ 56,370 
$ 17,649 
 
Amortization period
10 years 
 
 
Retirement Plan [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Benefit Obligation at Beginning of Period
1,097,421 
1,026,190 
999,499 
Service Cost
11,969 
11,710 
12,047 
Interest Cost
38,383 
42,315 
41,217 
Plan Participants' Contributions
Retiree Drug Subsidy Receipts
Amendments
1
1
7,752 1
Actuarial (Gain) Loss
(32,466)
76,309 
23,426 
Benefits Paid
(60,481)
(59,103)
(57,751)
Benefit Obligation at End of Period
1,054,826 
1,097,421 
1,026,190 
Fair Value of Assets at Beginning of Period
869,775 
834,870 
869,791 
Actual Return on Plan Assets
84,279 
87,008 
(13,370)
Employer Contributions
17,146 
7,000 
36,200 
Plan Participants' Contributions
Benefits Paid
(60,481)
(59,103)
(57,751)
Fair Value of Assets at End of Period
910,719 
869,775 
834,870 
Net Amount Recognized at End of Period (Funded Status)
(144,107)
(227,646)
(191,320)
Non-Current Liabilities
(144,107)
(227,646)
(191,320)
Non-Current Assets
Accumulated Benefit Obligation
1,010,179 
1,039,408 
968,984 
Discount Rate
3.77% 
3.60% 
4.25% 
Rate of Compensation Increase
4.70% 
4.70% 
4.75% 
Expected Return on Plan Assets
(59,718)
(59,369)
(59,615)
Amortization of Prior Service Cost (Credit)
1,058 
1,234 
183 
Recognition of Actuarial Loss
42,687 2
32,248 2
36,129 2
Net Amortization and Deferral for Regulatory Purposes
469 
3,957 
7,739 
Net Periodic Benefit Cost
34,848 
32,095 
37,700 
Discount Rate
3.60% 
4.25% 
4.25% 
Expected Return on Plan Assets
7.00% 
7.25% 
7.50% 
Rate of Compensation Increase
4.75% 
4.75% 
4.75% 
Other Post-Retirement Benefit Plans [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Benefit Obligation at Beginning of Period
526,138 
464,987 
465,583 
Service Cost
2,449 
2,331 
2,693 
Interest Cost
19,007 
20,386 
19,285 
Plan Participants' Contributions
2,717 
2,558 
2,242 
Retiree Drug Subsidy Receipts
1,553 
1,925 
1,338 
Amendments
1
1
1
Actuarial (Gain) Loss
(62,215)
60,402 
(1,575)
Benefits Paid
(27,030)
(26,451)
(24,579)
Benefit Obligation at End of Period
462,619 
526,138 
464,987 
Fair Value of Assets at Beginning of Period
494,320 
477,959 
497,601 
Actual Return on Plan Assets
40,157 
37,415 
534 
Employer Contributions
3,853 
2,839 
2,161 
Plan Participants' Contributions
2,717 
2,558 
2,242 
Benefits Paid
(27,030)
(26,451)
(24,579)
Fair Value of Assets at End of Period
514,017 
494,320 
477,959 
Net Amount Recognized at End of Period (Funded Status)
51,398 
(31,818)
12,972 
Non-Current Liabilities
(4,972)
(49,467)
(11,487)
Non-Current Assets
56,370 
17,649 
24,459 
Discount Rate
3.81% 
3.70% 
4.50% 
Rate of Compensation Increase
4.70% 
4.70% 
4.75% 
Expected Return on Plan Assets
(31,458)
(31,535)
(34,089)
Amortization of Prior Service Cost (Credit)
(429)
(912)
(1,913)
Recognition of Actuarial Loss
18,415 2
5,530 2
4,148 2
Net Amortization and Deferral for Regulatory Purposes
6,108 
17,123 
20,322 
Net Periodic Benefit Cost
$ 14,092 
$ 12,923 
$ 10,446 
Discount Rate
3.70% 
4.50% 
4.25% 
Expected Return on Plan Assets
6.50% 
6.75% 
7.00% 
Rate of Compensation Increase
4.75% 
4.75% 
4.75% 
Retirement Plan And Other Post-Retirement Benefits (Schedule Of Cumulative Amounts Recognized In AOCI (Loss) And Regulatory Assets And Liabilities) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Sep. 30, 2017
Non-Qualified Benefit Plans [Member]
 
Defined Benefit Plan Disclosure [Line Items]
 
Net Actuarial Loss
$ (24,332)1
Prior Service (Cost) Credit
1
Net Amount Recognized
(24,332)1
Decrease (Increase) in Actuarial Loss, excluding amortization
(1,351)1 2
Change due to Amortization of Actuarial Loss
4,059 1
Prior Service (Cost) Credit
1
Net Change
2,708 1
Net Actuarial Loss
(3,549)1
Prior Service (Cost) Credit
1
Net Amount Expected to be Recognized
(3,549)1
Retirement Plan [Member]
 
Defined Benefit Plan Disclosure [Line Items]
 
Net Actuarial Loss
(203,887)1
Prior Service (Cost) Credit
(6,133)1
Net Amount Recognized
(210,020)1
Decrease (Increase) in Actuarial Loss, excluding amortization
57,028 1 2
Change due to Amortization of Actuarial Loss
42,687 1
Prior Service (Cost) Credit
1,058 1
Net Change
100,773 1
Net Actuarial Loss
(37,205)1
Prior Service (Cost) Credit
(938)1
Net Amount Expected to be Recognized
(38,143)1
Other Post-Retirement Benefit Plans [Member]
 
Defined Benefit Plan Disclosure [Line Items]
 
Net Actuarial Loss
(19,578)1
Prior Service (Cost) Credit
3,687 1
Net Amount Recognized
(15,891)1
Decrease (Increase) in Actuarial Loss, excluding amortization
70,915 1 2
Change due to Amortization of Actuarial Loss
18,415 1
Prior Service (Cost) Credit
(429)1
Net Change
88,901 1
Net Actuarial Loss
(10,558)1
Prior Service (Cost) Credit
429 1
Net Amount Expected to be Recognized
$ (10,129)1
Retirement Plan And Other Post-Retirement Benefits (Schedule Of Expected Benefit Payments) (Details) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2017
Defined Benefit Plan Disclosure [Line Items]
 
2018 - Benefit Payments
$ 64,400 
2019 - Benefit Payments
65,000 
2020 - Benefit Payments
65,400 
2021 - Benefit Payments
65,800 
2022 - Benefit Payments
66,200 
2023 through 2027 - Benefit Payments
331,100 
Other Post-Retirement Benefit Plans [Member]
 
Defined Benefit Plan Disclosure [Line Items]
 
2018 - Benefit Payments
26,483 
2018 - Subsidy Receipts
(1,910)
2019 - Benefit Payments
27,456 
2019 - Subsidy Receipts
(2,074)
2020 - Benefit Payments
28,359 
2020 - Subsidy Receipts
(2,225)
2021 - Benefit Payments
29,173 
2021 - Subsidy Receipts
(2,369)
2022 - Benefit Payments
29,757 
2022 - Subsidy Receipts
(2,515)
2023 through 2027 - Benefit Payments
152,957 
2023 through 2027 - Subsidy Receipts
$ (14,271)
Retirement Plan And Other Post-Retirement Benefits (Schedule Of Health Care Cost Trend Rates) (Details)
12 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
Retirement Benefits [Abstract]
 
 
 
Rate of Medical Cost Increase for Pre Age 65 Participants
5.67% 1
5.75% 1
6.93% 2
Rate of Medical Cost Increase for Post Age 65 Participants
4.75% 1
4.75% 1
6.68% 2
Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits
8.45% 1
9.00% 1
7.17% 2
Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement
4.75% 1
4.75% 1
6.68% 2
Annual Rate of Increase in the Per Capita Medicare Part D Subsidy
7.33% 1
7.20% 1
6.65% 2
Ultimate Health Care Trend Rate
4.50% 
4.50% 
4.50% 
Retirement Plan And Other Post-Retirement Benefits (Schedule Of Fair Value Of Plan Assets) (Details) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
Sep. 30, 2014
Retirement Plan [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
$ 910,719 
$ 869,775 
$ 834,870 
$ 869,791 
Retirement Plan [Member] |
Domestic Equities [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
290,716 1
256,796 1
 
 
Investments Measured at NAV
81,295 1 2
68,543 1 2
 
 
Retirement Plan [Member] |
International Equities [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
123,069 3
104,592 3
 
 
Investments Measured at NAV
123,069 2 3
104,592 2 3
 
 
Retirement Plan [Member] |
Global Equities [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
121,008 4
120,025 4
 
 
Investments Measured at NAV
121,008 2 4
120,025 2 4
 
 
Retirement Plan [Member] |
Domestic Fixed Income [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
348,501 5
342,442 5
 
 
Investments Measured at NAV
2 5
2 5
 
 
Retirement Plan [Member] |
International Fixed Income [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
422 6
744 6
 
 
Investments Measured at NAV
2 6
2 6
 
 
Retirement Plan [Member] |
Global Fixed Income [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
75,428 7
81,146 7
 
 
Investments Measured at NAV
75,428 2 7
81,146 2 7
 
 
Retirement Plan [Member] |
Real Estate [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
3,391 
2,970 
 
 
Investments Measured at NAV
2
2
 
 
Retirement Plan [Member] |
Retirement Plan Investments [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
988,593 
933,527 
 
 
Investments Measured at NAV
426,858 2
399,118 2
 
 
Retirement Plan [Member] |
401(h) Investments [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
(64,728)
(58,707)
 
 
Investments Measured at NAV
(27,476)2
(24,939)2
 
 
Retirement Plan [Member] |
Total Retirement Plan Investments Excluding 401 H Investments [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
923,865 
874,820 
 
 
Investments Measured at NAV
399,382 2
374,179 2
 
 
Retirement Plan [Member] |
Cash Held In Collective Trust Funds [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
26,058 
24,812 
 
 
Investments Measured at NAV
26,058 2
24,812 2
 
 
Other Post-Retirement Benefit Plans [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
514,017 
494,320 
477,959 
497,601 
Other Post-Retirement Benefit Plans [Member] |
401(h) Investments [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
64,728 
58,707 
 
 
Investments Measured at NAV
27,476 2
24,939 2
 
 
Other Post-Retirement Benefit Plans [Member] |
Collective Trust Funds Domestic Equities [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
130,864 
139,617 
 
 
Investments Measured at NAV
130,864 2
139,617 2
 
 
Other Post-Retirement Benefit Plans [Member] |
Collective Trust Funds International Equities [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
52,063 
51,488 
 
 
Investments Measured at NAV
52,063 2
51,488 2
 
 
Other Post-Retirement Benefit Plans [Member] |
Exchange Traded Funds Fixed Income [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
256,099 
230,761 
 
 
Investments Measured at NAV
2
2
 
 
Other Post-Retirement Benefit Plans [Member] |
Cash Held In Collective Trust Funds [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
9,569 
13,176 
 
 
Investments Measured at NAV
9,569 2
13,176 2
 
 
Other Post-Retirement Benefit Plans [Member] |
Total VEBA Trust Investments [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
448,595 
435,042 
 
 
Investments Measured at NAV
192,496 2
204,281 2
 
 
Other Post-Retirement Benefit Plans [Member] |
Total Investments Including 401H Investments [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
513,323 
493,749 
 
 
Investments Measured at NAV
219,972 2
229,220 2
 
 
Fair Value, Inputs, Level 1 [Member] |
Retirement Plan [Member] |
Domestic Equities [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
209,421 1
188,253 1
 
 
Fair Value, Inputs, Level 1 [Member] |
Retirement Plan [Member] |
International Equities [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
3
3
 
 
Fair Value, Inputs, Level 1 [Member] |
Retirement Plan [Member] |
Global Equities [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
4
4
 
 
Fair Value, Inputs, Level 1 [Member] |
Retirement Plan [Member] |
Domestic Fixed Income [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
1,664 5
1,647 5
 
 
Fair Value, Inputs, Level 1 [Member] |
Retirement Plan [Member] |
International Fixed Income [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
422 6
407 6
 
 
Fair Value, Inputs, Level 1 [Member] |
Retirement Plan [Member] |
Global Fixed Income [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
7
7
 
 
Fair Value, Inputs, Level 1 [Member] |
Retirement Plan [Member] |
Real Estate [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
 
 
Fair Value, Inputs, Level 1 [Member] |
Retirement Plan [Member] |
Retirement Plan Investments [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
211,507 
190,307 
 
 
Fair Value, Inputs, Level 1 [Member] |
Retirement Plan [Member] |
401(h) Investments [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
(14,026)
(12,025)
 
 
Fair Value, Inputs, Level 1 [Member] |
Retirement Plan [Member] |
Total Retirement Plan Investments Excluding 401 H Investments [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
197,481 
178,282 
 
 
Fair Value, Inputs, Level 1 [Member] |
Retirement Plan [Member] |
Cash Held In Collective Trust Funds [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
 
 
Fair Value, Inputs, Level 1 [Member] |
Other Post-Retirement Benefit Plans [Member] |
401(h) Investments [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
14,026 
12,025 
 
 
Fair Value, Inputs, Level 1 [Member] |
Other Post-Retirement Benefit Plans [Member] |
Collective Trust Funds Domestic Equities [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
 
 
Fair Value, Inputs, Level 1 [Member] |
Other Post-Retirement Benefit Plans [Member] |
Collective Trust Funds International Equities [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
 
 
Fair Value, Inputs, Level 1 [Member] |
Other Post-Retirement Benefit Plans [Member] |
Exchange Traded Funds Fixed Income [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
256,099 
230,761 
 
 
Fair Value, Inputs, Level 1 [Member] |
Other Post-Retirement Benefit Plans [Member] |
Cash Held In Collective Trust Funds [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
 
 
Fair Value, Inputs, Level 1 [Member] |
Other Post-Retirement Benefit Plans [Member] |
Total VEBA Trust Investments [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
256,099 
230,761 
 
 
Fair Value, Inputs, Level 1 [Member] |
Other Post-Retirement Benefit Plans [Member] |
Total Investments Including 401H Investments [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
270,125 
242,786 
 
 
Fair Value, Inputs, Level 2 [Member] |
Retirement Plan [Member] |
Domestic Equities [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
1
1
 
 
Fair Value, Inputs, Level 2 [Member] |
Retirement Plan [Member] |
International Equities [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
3
3
 
 
Fair Value, Inputs, Level 2 [Member] |
Retirement Plan [Member] |
Global Equities [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
4
4
 
 
Fair Value, Inputs, Level 2 [Member] |
Retirement Plan [Member] |
Domestic Fixed Income [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
346,837 5
340,795 5
 
 
Fair Value, Inputs, Level 2 [Member] |
Retirement Plan [Member] |
International Fixed Income [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
6
337 6
 
 
Fair Value, Inputs, Level 2 [Member] |
Retirement Plan [Member] |
Global Fixed Income [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
7
7
 
 
Fair Value, Inputs, Level 2 [Member] |
Retirement Plan [Member] |
Real Estate [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
 
 
Fair Value, Inputs, Level 2 [Member] |
Retirement Plan [Member] |
Retirement Plan Investments [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
346,837 
341,132 
 
 
Fair Value, Inputs, Level 2 [Member] |
Retirement Plan [Member] |
401(h) Investments [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
(23,001)
(21,555)
 
 
Fair Value, Inputs, Level 2 [Member] |
Retirement Plan [Member] |
Total Retirement Plan Investments Excluding 401 H Investments [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
323,836 
319,577 
 
 
Fair Value, Inputs, Level 2 [Member] |
Retirement Plan [Member] |
Cash Held In Collective Trust Funds [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
 
 
Fair Value, Inputs, Level 2 [Member] |
Other Post-Retirement Benefit Plans [Member] |
401(h) Investments [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
23,001 
21,555 
 
 
Fair Value, Inputs, Level 2 [Member] |
Other Post-Retirement Benefit Plans [Member] |
Collective Trust Funds Domestic Equities [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
 
 
Fair Value, Inputs, Level 2 [Member] |
Other Post-Retirement Benefit Plans [Member] |
Collective Trust Funds International Equities [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
 
 
Fair Value, Inputs, Level 2 [Member] |
Other Post-Retirement Benefit Plans [Member] |
Exchange Traded Funds Fixed Income [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
 
 
Fair Value, Inputs, Level 2 [Member] |
Other Post-Retirement Benefit Plans [Member] |
Cash Held In Collective Trust Funds [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
 
 
Fair Value, Inputs, Level 2 [Member] |
Other Post-Retirement Benefit Plans [Member] |
Total VEBA Trust Investments [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
 
 
Fair Value, Inputs, Level 2 [Member] |
Other Post-Retirement Benefit Plans [Member] |
Total Investments Including 401H Investments [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
23,001 
21,555 
 
 
Fair Value, Inputs, Level 3 [Member] |
Retirement Plan [Member] |
Domestic Equities [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
1
1
 
 
Fair Value, Inputs, Level 3 [Member] |
Retirement Plan [Member] |
International Equities [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
3
3
 
 
Fair Value, Inputs, Level 3 [Member] |
Retirement Plan [Member] |
Global Equities [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
4
4
 
 
Fair Value, Inputs, Level 3 [Member] |
Retirement Plan [Member] |
Domestic Fixed Income [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
5
5
 
 
Fair Value, Inputs, Level 3 [Member] |
Retirement Plan [Member] |
International Fixed Income [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
6
6
 
 
Fair Value, Inputs, Level 3 [Member] |
Retirement Plan [Member] |
Global Fixed Income [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
7
7
 
 
Fair Value, Inputs, Level 3 [Member] |
Retirement Plan [Member] |
Real Estate [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
3,391 
2,970 
 
 
Fair Value, Inputs, Level 3 [Member] |
Retirement Plan [Member] |
Retirement Plan Investments [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
3,391 
2,970 
 
 
Fair Value, Inputs, Level 3 [Member] |
Retirement Plan [Member] |
401(h) Investments [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
(225)
(188)
 
 
Fair Value, Inputs, Level 3 [Member] |
Retirement Plan [Member] |
Total Retirement Plan Investments Excluding 401 H Investments [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
3,166 
2,782 
 
 
Fair Value, Inputs, Level 3 [Member] |
Retirement Plan [Member] |
Cash Held In Collective Trust Funds [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
 
 
Fair Value, Inputs, Level 3 [Member] |
Other Post-Retirement Benefit Plans [Member] |
401(h) Investments [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
225 
188 
 
 
Fair Value, Inputs, Level 3 [Member] |
Other Post-Retirement Benefit Plans [Member] |
Collective Trust Funds Domestic Equities [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
 
 
Fair Value, Inputs, Level 3 [Member] |
Other Post-Retirement Benefit Plans [Member] |
Collective Trust Funds International Equities [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
 
 
Fair Value, Inputs, Level 3 [Member] |
Other Post-Retirement Benefit Plans [Member] |
Exchange Traded Funds Fixed Income [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
 
 
Fair Value, Inputs, Level 3 [Member] |
Other Post-Retirement Benefit Plans [Member] |
Cash Held In Collective Trust Funds [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
 
 
Fair Value, Inputs, Level 3 [Member] |
Other Post-Retirement Benefit Plans [Member] |
Total VEBA Trust Investments [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
 
 
Fair Value, Inputs, Level 3 [Member] |
Other Post-Retirement Benefit Plans [Member] |
Total Investments Including 401H Investments [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
225 
188 
 
 
Miscellaneous Accruals, Interest Receivables, And Non-Interest Cash [Member] |
Retirement Plan [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
(13,146)
(5,045)
 
 
Miscellaneous Accruals Including Current and Deferred Taxes Claims Incurred But Not Reported Administrative [Member] |
Other Post-Retirement Benefit Plans [Member]
 
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Fair Value of Investments
$ 694 
$ 571 
 
 
Retirement Plan And Other Post-Retirement Benefits (Schedule Of Significant Unobservable Input Changes In Plan Assets) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Retirement Plan [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Balance, Beginning of Year
$ 2,782 
$ 29,329 
Realized Gains/(Losses)
 
5,524 
Unrealized Gains/(Losses)
384 
(5,505)
Sales
 
(26,566)
Balance, End of Year
3,166 
2,782 
Hedge Funds Investments [Member] |
Retirement Plan [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Balance, Beginning of Year
26,490 
Realized Gains/(Losses)
 
5,878 
Unrealized Gains/(Losses)
(5,445)
Sales
 
(26,923)
Balance, End of Year
Real Estate [Member] |
Retirement Plan [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Balance, Beginning of Year
2,970 
4,724 
Realized Gains/(Losses)
 
Unrealized Gains/(Losses)
421 
(404)
Sales
 
(1,350)
Balance, End of Year
3,391 
2,970 
Excluding 401(h) Investments [Member] |
Retirement Plan [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Balance, Beginning of Year
(188)
(1,885)
Realized Gains/(Losses)
 
(354)
Unrealized Gains/(Losses)
(37)
344 
Sales
 
1,707 
Balance, End of Year
(225)
(188)
401(h) Investments [Member] |
Other Post-Retirement Benefit Plans [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Balance, Beginning of Year
188 
1,885 
Realized Gains/(Losses)
 
354 
Unrealized Gains/(Losses)
37 
(344)
Sales
 
(1,707)
Balance, End of Year
$ 225 
$ 188 
Commitments And Contingencies (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2017
Site Contingency [Line Items]
 
Estimate minimum liability for environmental remediation
$ 3.1 
Project Costs
75.8 
Future purchase obligation first year
262.4 
Future purchase obligation second year
84.6 
Future purchase obligation third year
77.9 
Future purchase obligation fourth year
70.9 
Future purchase obligation fifth year
61.7 
Future purchase obligation thereafter
504.9 
Operating lease commitment first year
10.8 
Operating lease commitment second year
4.6 
Operating lease commitment third year
3.7 
Operating lease commitment fourth year
2.2 
Operating lease commitment fifth year
1.5 
Operating lease commitment thereafter
1.9 
Environmental Site Remediation Costs [Member]
 
Site Contingency [Line Items]
 
Rate recovery period
4 years 
Pipeline And Storage, Gathering And Utility Segments [Member]
 
Site Contingency [Line Items]
 
Contract commitments first year
61.7 
Contract commitments second year
0.7 
Contract commitments third year
0.2 
Contractual commitments fourth year
0.3 
Contractual commitments fifth year
0.3 
Contractual commitments thereafter
1.1 
Exploration And Production [Member]
 
Site Contingency [Line Items]
 
Contract commitments first year
79.5 
Contract commitments second year
98.0 
Contract commitments third year
$ 17.1 
Business Segment Information (Narrative) (Details)
12 Months Ended
Sep. 30, 2017
segment
Segment Reporting [Abstract]
 
Number of Reportable Segments
Business Segment Information (Segment Information By Segment) (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 12 Months Ended
Sep. 30, 2017
Jun. 30, 2017
Mar. 31, 2017
Dec. 31, 2016
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Dec. 31, 2015
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Interest Income
 
 
 
 
 
 
 
 
$ 4,113 
$ 4,235 
$ 3,922 
Interest Expense
 
 
 
 
 
 
 
 
119,837 
121,044 
99,471 
Depreciation, Depletion and Amortization
 
 
 
 
 
 
 
 
224,195 
249,417 
336,158 
Income Tax Expense (Benefit)
 
 
 
 
 
 
 
 
160,682 
(232,549)
(319,136)
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties
 
 
 
 
32,700 
82,700 
397,400 
435,500 
948,307 
1,126,257 
Segment Profit: Net Income (Loss)
45,577 
59,714 
89,283 
88,908 
37,553 1
8,286 2
(147,688)3
(189,109)4
283,482 
(290,958)
(379,427)
Expenditures for Additions to Long-Lived Assets
 
 
 
 
 
 
 
 
462,117 
523,051 
1,000,509 
Segment Assets
6,103,320 
 
 
 
5,636,387 
 
 
 
6,103,320 
5,636,387 
6,564,939 
Utility [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Interest Income
 
 
 
 
 
 
 
 
1,051 
1,737 
2,220 
Interest Expense
 
 
 
 
 
 
 
 
28,492 
27,582 
28,176 
Depreciation, Depletion and Amortization
 
 
 
 
 
 
 
 
52,582 
48,618 
45,616 
Income Tax Expense (Benefit)
 
 
 
 
 
 
 
 
24,894 
25,602 
33,143 
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties
 
 
 
 
 
 
 
 
 
Segment Profit: Net Income (Loss)
 
 
 
 
 
 
 
 
46,935 
50,960 
63,271 
Expenditures for Additions to Long-Lived Assets
 
 
 
 
 
 
 
 
80,867 
98,007 
94,371 
Segment Assets
2,013,123 
 
 
 
2,021,514 
 
 
 
2,013,123 
2,021,514 
1,934,731 
Pipeline And Storage [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Interest Income
 
 
 
 
 
 
 
 
1,467 
770 
474 
Interest Expense
 
 
 
 
 
 
 
 
33,717 
33,327 
27,658 
Depreciation, Depletion and Amortization
 
 
 
 
 
 
 
 
41,196 
43,273 
38,178 
Income Tax Expense (Benefit)
 
 
 
 
 
 
 
 
40,947 
50,241 
48,113 
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties
 
 
 
 
 
 
 
 
 
Segment Profit: Net Income (Loss)
 
 
 
 
 
 
 
 
68,446 
76,610 
80,354 
Expenditures for Additions to Long-Lived Assets
 
 
 
 
 
 
 
 
95,336 
114,250 
230,192 
Segment Assets
1,929,788 
 
 
 
1,680,734 
 
 
 
1,929,788 
1,680,734 
1,590,524 
Exploration And Production [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Interest Income
 
 
 
 
 
 
 
 
707 
858 
2,554 
Interest Expense
 
 
 
 
 
 
 
 
53,702 
55,434 
46,726 
Depreciation, Depletion and Amortization
 
 
 
 
 
 
 
 
112,565 
139,963 
239,818 
Income Tax Expense (Benefit)
 
 
 
 
 
 
 
 
66,093 
(334,029)
(428,217)
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties
 
 
 
 
 
 
 
 
 
948,307 
1,126,257 
Segment Profit: Net Income (Loss)
 
 
 
 
 
 
 
 
129,326 
(452,842)
(556,974)
Expenditures for Additions to Long-Lived Assets
 
 
 
 
 
 
 
 
253,057 
256,104 
557,313 
Segment Assets
1,407,152 
 
 
 
1,323,081 
 
 
 
1,407,152 
1,323,081 
2,439,801 
Energy Marketing [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Interest Income
 
 
 
 
 
 
 
 
571 
422 
195 
Interest Expense
 
 
 
 
 
 
 
 
47 
49 
27 
Depreciation, Depletion and Amortization
 
 
 
 
 
 
 
 
279 
278 
209 
Income Tax Expense (Benefit)
 
 
 
 
 
 
 
 
891 
2,460 
4,547 
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties
 
 
 
 
 
 
 
 
 
Segment Profit: Net Income (Loss)
 
 
 
 
 
 
 
 
1,509 
4,348 
7,766 
Expenditures for Additions to Long-Lived Assets
 
 
 
 
 
 
 
 
36 
34 
128 
Segment Assets
60,937 
 
 
 
63,392 
 
 
 
60,937 
63,392 
90,676 
Gathering [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Interest Income
 
 
 
 
 
 
 
 
994 
297 
140 
Interest Expense
 
 
 
 
 
 
 
 
9,142 
8,872 
1,627 
Depreciation, Depletion and Amortization
 
 
 
 
 
 
 
 
16,162 
15,282 
10,829 
Income Tax Expense (Benefit)
 
 
 
 
 
 
 
 
29,694 
24,334 
24,721 
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties
 
 
 
 
 
 
 
 
 
Segment Profit: Net Income (Loss)
 
 
 
 
 
 
 
 
40,377 
30,499 
31,849 
Expenditures for Additions to Long-Lived Assets
 
 
 
 
 
 
 
 
32,645 
54,293 
118,166 
Segment Assets
580,051 
 
 
 
534,259 
 
 
 
580,051 
534,259 
444,358 
Total Reportable Segments [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Interest Income
 
 
 
 
 
 
 
 
4,790 
4,084 
5,583 
Interest Expense
 
 
 
 
 
 
 
 
125,100 
125,264 
104,214 
Depreciation, Depletion and Amortization
 
 
 
 
 
 
 
 
222,784 
247,414 
334,650 
Income Tax Expense (Benefit)
 
 
 
 
 
 
 
 
162,519 
(231,392)
(317,693)
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties
 
 
 
 
 
 
 
 
 
948,307 
1,126,257 
Segment Profit: Net Income (Loss)
 
 
 
 
 
 
 
 
286,593 
(290,425)
(373,734)
Expenditures for Additions to Long-Lived Assets
 
 
 
 
 
 
 
 
461,941 
522,688 
1,000,170 
Segment Assets
5,991,051 
 
 
 
5,622,980 
 
 
 
5,991,051 
5,622,980 
6,500,090 
All Other [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Interest Income
 
 
 
 
 
 
 
 
213 
117 
66 
Interest Expense
 
 
 
 
 
 
 
 
Depreciation, Depletion and Amortization
 
 
 
 
 
 
 
 
661 
1,260 
832 
Income Tax Expense (Benefit)
 
 
 
 
 
 
 
 
(247)
561 
13 
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties
 
 
 
 
 
 
 
 
 
Segment Profit: Net Income (Loss)
 
 
 
 
 
 
 
 
(342)
778 
(2)
Expenditures for Additions to Long-Lived Assets
 
 
 
 
 
 
 
 
39 
37 
Segment Assets
76,861 
 
 
 
77,138 
 
 
 
76,861 
77,138 
77,350 
Corporate And Intersegment Eliminations [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Interest Income
 
 
 
 
 
 
 
 
(890)
34 
(1,727)
Interest Expense
 
 
 
 
 
 
 
 
(5,263)
(4,220)
(4,743)
Depreciation, Depletion and Amortization
 
 
 
 
 
 
 
 
750 
743 
676 
Income Tax Expense (Benefit)
 
 
 
 
 
 
 
 
(1,590)
(1,718)
(1,456)
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties
 
 
 
 
 
 
 
 
 
Segment Profit: Net Income (Loss)
 
 
 
 
 
 
 
 
(2,769)
(1,311)
(5,691)
Expenditures for Additions to Long-Lived Assets
 
 
 
 
 
 
 
 
137 
326 
339 
Segment Assets
35,408 
 
 
 
(63,731)
 
 
 
35,408 
(63,731)
(12,501)
Revenue from External Customers [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenue
 
 
 
 
 
 
 
 
1,579,881 5
1,452,416 5
1,760,913 5
Revenue from External Customers [Member] |
Utility [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenue
 
 
 
 
 
 
 
 
626,899 5
531,024 5
700,761 5
Revenue from External Customers [Member] |
Pipeline And Storage [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenue
 
 
 
 
 
 
 
 
206,615 5
215,674 5
203,089 5
Revenue from External Customers [Member] |
Exploration And Production [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenue
 
 
 
 
 
 
 
 
614,599 5
607,113 5
693,441 5
Revenue from External Customers [Member] |
Energy Marketing [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenue
 
 
 
 
 
 
 
 
128,586 5
93,578 5
159,857 5
Revenue from External Customers [Member] |
Gathering [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenue
 
 
 
 
 
 
 
 
115 5
374 5
497 5
Revenue from External Customers [Member] |
Total Reportable Segments [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenue
 
 
 
 
 
 
 
 
1,576,814 5
1,447,763 5
1,757,645 5
Revenue from External Customers [Member] |
All Other [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenue
 
 
 
 
 
 
 
 
2,173 5
3,753 5
2,352 5
Revenue from External Customers [Member] |
Corporate And Intersegment Eliminations [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenue
 
 
 
 
 
 
 
 
894 5
900 5
916 5
Intersegment Revenues [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenue
 
 
 
 
 
 
 
 
Intersegment Revenues [Member] |
Utility [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenue
 
 
 
 
 
 
 
 
13,072 
13,123 
15,506 
Intersegment Revenues [Member] |
Pipeline And Storage [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenue
 
 
 
 
 
 
 
 
87,810 
90,755 
88,251 
Intersegment Revenues [Member] |
Exploration And Production [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenue
 
 
 
 
 
 
 
 
Intersegment Revenues [Member] |
Energy Marketing [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenue
 
 
 
 
 
 
 
 
794 
884 
849 
Intersegment Revenues [Member] |
Gathering [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenue
 
 
 
 
 
 
 
 
107,566 
89,073 
76,709 
Intersegment Revenues [Member] |
Total Reportable Segments [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenue
 
 
 
 
 
 
 
 
209,242 
193,835 
181,315 
Intersegment Revenues [Member] |
All Other [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenue
 
 
 
 
 
 
 
 
Intersegment Revenues [Member] |
Corporate And Intersegment Eliminations [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenue
 
 
 
 
 
 
 
 
$ (209,242)
$ (193,835)
$ (181,315)
Business Segment Information (Schedule Of Long-Lived Assets, By Geographical Areas) (Details) (United States [Member], USD $)
In Thousands, unless otherwise specified
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
United States [Member]
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
Long-Lived Assets
$ 5,285,040 
$ 5,223,356 
$ 6,189,138 
Quarterly Financial Data (Schedule Of Quarterly Financial Information) (Details) (USD $)
3 Months Ended 12 Months Ended
Sep. 30, 2017
Jun. 30, 2017
Mar. 31, 2017
Dec. 31, 2016
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Dec. 31, 2015
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
Operating Revenues
$ 286,937,000 
$ 348,369,000 
$ 522,075,000 
$ 422,500,000 
$ 292,472,000 
$ 335,617,000 
$ 449,132,000 
$ 375,195,000 
$ 1,579,881,000 
$ 1,452,416,000 
$ 1,760,913,000 
Operating Income (Loss)
87,395,000 
123,354,000 
169,957,000 
172,139,000 
81,244,000 
45,162,000 
(237,000,000)
(305,924,000)
552,845,000 
(416,518,000)
(611,053,000)
Net Income (Loss) Available for Common Stock
45,577,000 
59,714,000 
89,283,000 
88,908,000 
37,553,000 1
8,286,000 2
(147,688,000)3
(189,109,000)4
283,482,000 
(290,958,000)
(379,427,000)
Earnings (Loss) per Common Share, Basic
$ 0.53 
$ 0.70 
$ 1.05 
$ 1.04 
$ 0.44 
$ 0.10 
$ (1.74)
$ (2.23)
$ 3.32 
$ (3.43)
$ (4.50)
Earnings (Loss) per Common Share, Diluted
$ 0.53 
$ 0.69 
$ 1.04 
$ 1.04 
$ 0.44 
$ 0.10 
$ (1.74)
$ (2.23)
$ 3.30 
$ (3.43)
$ (4.50)
Impairment of Oil and Gas Producing Properties
 
 
 
 
32,700,000 
82,700,000 
397,400,000 
435,500,000 
948,307,000 
1,126,257,000 
Impairment of Oil and Gas Producing Properties After Tax
 
 
 
 
$ 19,000,000 
$ 47,900,000 
$ 230,500,000 
$ 252,600,000 
 
 
 
Supplementary Information For Oil And Gas Producing Activities (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Sep. 30, 2017
ft3
Sep. 30, 2016
ft3
Sep. 30, 2015
ft3
Sep. 30, 2014
Sep. 30, 2013
Reserve Quantities [Line Items]
 
 
 
 
 
Amount spent for developing proved undeveloped reserves
$ 101.1 
$ 92.8 
$ 161.8 
 
 
Proved Undeveloped Reserve (Volume)
612,000,000,000 
543,000,000,000 
827,000,000,000 
 
 
Percentage of PUD reserves to the total proved reserves
28.00% 
29.00% 
35.00% 
 
 
New PUD reserve additions
269,000,000,000 
102,000,000,000 
 
 
 
PUD Sales
 
166,000,000,000 
 
 
 
PUD Downward Revisions
 
14,000,000,000 
 
 
 
PUD Upward Revisions
13,000,000,000 
 
 
 
 
PUD conversions to developed reserves
159,000,000,000 
110,000,000,000 
 
 
 
Proved Undeveloped Reserves, Removed
54,000,000,000 
96,000,000,000 
 
 
 
Decrease in Proved undeveloped (PUD) reserves
 
284,000,000,000 
 
 
 
Increase in Proved undeveloped (PUD) reserves
69,000,000,000 
 
 
 
 
Investment made to convert proved undeveloped reserves to developed reserves
101 
93 
 
 
 
Reimbursed Drilling Carry Costs for JDA Partner
 
36 
 
 
 
Conversion of undeveloped proved reserves to developed proved reserves
147,000,000,000 
92,000,000,000 
 
 
 
Conversion of PUD to Developed as a Percentage of PUD Reserves Booked at End of Prior Year
27.00% 
11.00% 
33.00% 
51.00% 
39.00% 
Wells Developed
37 
 
 
 
 
Percent Wells Developed
41.00% 
 
 
 
 
Arbitrary discount rate
10.00% 
 
 
 
 
West Coast Region [Member]
 
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
 
New PUD reserve additions
2,000,000,000 
 
 
 
 
PUD conversions to developed reserves
1,000,000,000 
 
 
 
 
Marcellus Shale Fields [Member]
 
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
 
Proved Undeveloped Reserve (Volume)
456,000,000,000 
542,000,000,000 
825,000,000,000 
 
 
New PUD reserve additions
113,000,000,000 
102,000,000,000 
 
 
 
PUD conversions to developed reserves
158,000,000,000 
 
 
 
 
Proved Undeveloped Reserves, Removed
 
74,000,000,000 
 
 
 
Wells Developed
 
31 
 
 
 
Percent Wells Developed
 
28.00% 
 
 
 
Utica Shale [Member]
 
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
 
New PUD reserve additions
154,000,000,000 
 
 
 
 
Geneseo Shale [Member]
 
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
 
Proved Undeveloped Reserves, Removed
 
23,000,000,000 
 
 
 
Will Not Meet 5 Year Requirement for Proved Reserves [Member] |
Marcellus Shale Fields [Member]
 
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
 
Proved Undeveloped Reserves, Removed
36,000,000,000 
 
 
 
 
Change in Development Plans [Member] |
Marcellus Shale Fields [Member]
 
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
 
Proved Undeveloped Reserves, Removed
18,000,000,000 
 
 
 
 
Total PUD Reserve Additions Estimated In The Next Fiscal Year [Member]
 
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
 
Amount to be spent on developing proved undeveloped reserves
$ 186 
 
 
 
 
Conversion Of Undeveloped Proved Reserves To Developed Proved Reserves Before Revisions [Member]
 
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
 
Conversion of undeveloped proved reserves to developed proved reserves
159,000,000,000 
110,000,000,000 
 
 
 
Impact of JDA Sales [Member]
 
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
 
Conversion of undeveloped proved reserves to developed proved reserves
 
207,000,000,000 
 
 
 
Conversion of PUD to Developed as a Percentage of PUD Reserves Booked at End of Prior Year
 
25.00% 
 
 
 
Anticipated JDA Sales [Member]
 
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
 
PUD Sales
60,000,000,000 
 
 
 
 
Supplementary Information For Oil And Gas Producing Activities (Capitalized Costs Relating To Oil And Gas Producing Activities) (Details) (USD $)
Sep. 30, 2017
Sep. 30, 2016
Supplementary Information For Oil And Gas Producing Activities Unaudited [Abstract]
 
 
Proved Properties
$ 4,832,301,000 1
$ 4,554,929,000 1
Unproved Properties
80,932,000 
135,285,000 
Capitalized Costs, Oil and Gas Producing Activities, Gross, Total
4,913,233,000 
4,690,214,000 
Less - Accumulated Depreciation, Depletion and Amortization
3,765,710,000 
3,657,239,000 
Capitalized Costs Oil And Gas Producing Activities Net
1,147,523,000 
1,032,975,000 
Asset retirement costs
$ 54,400,000 
$ 63,600,000 
Supplementary Information For Oil And Gas Producing Activities (Summary Of Capitalized Costs Of Unproved Properties Excluded From Amortization) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
Sep. 30, 2017
Capitalized Costs Of Unproved Properties Cumulative Balance [Member]
Sep. 30, 2014
Costs Incurred Prior To Fiscal 2015 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
 
 
 
 
 
Acquisition Costs
$ 0 
$ 0 
$ 0 
$ 55,193 
$ 55,193 
Development Costs
4,388 
6,707 
416 
11,879 
368 
Exploration Costs
2,376 
7,593 
3,419 
13,388 
Capitalized Interest
235 
149 
88 
472 
Capitalized Costs of Unproved Properties Excluded from Amortization, Total
$ 6,999 
$ 14,449 
$ 3,923 
$ 80,932 
$ 55,561 
Supplementary Information For Oil And Gas Producing Activities (Costs Incurred In Oil And Gas Property Acquisition, Exploration And Development Activities) (Details) (USD $)
12 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
Supplementary Information For Oil And Gas Producing Activities Unaudited [Abstract]
 
 
 
Proved
$ 8,908,000 
$ 1,342,000 
$ 1,767,000 
Unproved
262,000 
2,165,000 
19,998,000 
Exploration Costs
40,975,000 1
27,561,000 1
53,222,000 1
Development Costs
200,639,000 2
219,386,000 2
454,605,000 2
Asset Retirement Costs
(9,175,000)
(49,653,000)
37,595,000 
Total Property Acquisition Costs
241,609,000 
200,801,000 
567,187,000 
Capitalized interest included in exploration costs
300,000 
300,000 
400,000 
Capitalized interest included in development costs
$ 200,000 
$ 200,000 
$ 500,000 
Supplementary Information For Oil And Gas Producing Activities (Results Of Operations For Producing Activities) (Details) (USD $)
12 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
Reserve Quantities [Line Items]
 
 
 
Revenues from sales to affiliates
$ 0 
$ 0 
$ 0 
Operating Revenues
526,492,000 1
386,152,000 1
506,721,000 1
Production/Lifting Costs
165,991,000 
153,914,000 
167,800,000 
Franchise/Ad Valorem Taxes
15,372,000 
13,794,000 
20,167,000 
Purchased Emission Allowance Expense
1,391,000 
700,000 
3,089,000 
Accretion Expense
4,896,000 
6,663,000 
6,186,000 
Depreciation, Depletion and Amortization ($0.63, $0.85 and $1.49 per Mcfe of production)
108,471,000 
136,579,000 
234,480,000 
Impairment of Oil and Gas Producing Properties
948,307,000 
1,126,257,000 
Income Tax Expense (Benefit)
86,657,000 
(368,940,000)
(444,393,000)
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)
143,714,000 
(504,865,000)
(606,865,000)
Depreciation, Depletion and Amortization, per Mcfe of Production
0.63 
0.85 
1.49 
Transfers to Entity's Other Operations
2,357,000 
1,765,000 
1,946,000 
Natural Gas [Member]
 
 
 
Reserve Quantities [Line Items]
 
 
 
Natural Gas (includes transfers to operations of $2,357, $1,765 and $1,946, respectively)
399,975,000 2
282,619,000 2
350,673,000 2
Oil, Condensate And Other Liquids [Member]
 
 
 
Reserve Quantities [Line Items]
 
 
 
Operating Revenues
$ 126,517,000 
$ 103,533,000 
$ 156,048,000 
Supplementary Information For Oil And Gas Producing Activities (Proved Developed And Undeveloped Oil And Gas Reserve Quantities) (Details)
12 Months Ended
Sep. 30, 2017
MMcf
Sep. 30, 2016
MMcf
Sep. 30, 2015
MMcf
Sep. 30, 2014
MMcf
Reserve Quantities [Line Items]
 
 
 
 
Proved Undeveloped Reserve (Volume)
612,000,000,000 
543,000,000,000 
827,000,000,000 
 
Natural Gas (Mmcf) [Member]
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
Proved Developed and Undeveloped Reserves
1,674,575 
2,142,128 
1,682,884 
 
Extensions and Discoveries
386,657 
185,347 
633,360 
 
Revisions of Previous Estimates
90,849 
(248,161)
(34,441)
 
Production Volume
(157,088)
(143,547)
(139,563)
 
Sales of Minerals in Place
(21,873)
(261,192)
(112)
 
Proved Developed and Undeveloped Reserves
1,973,120 
1,674,575 
2,142,128 
 
Proved Developed Reserves (Volume)
1,363,102 
1,132,616 
1,316,844 
1,177,808 
Proved Undeveloped Reserve (Volume)
610,018 
541,959 
825,284 
505,076 
Oil Mbbl [Member]
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
Proved Developed and Undeveloped Reserves
29,009 
33,722 
38,477 
 
Extensions and Discoveries
674 
530 
533 
 
Revisions of Previous Estimates
3,293 
(2,247)
(2,254)
 
Production Volume
(2,740)
(2,923)
(3,034)
 
Sales of Minerals in Place
(29)
73 
 
 
Proved Developed and Undeveloped Reserves
30,207 
29,009 
33,722 
 
Proved Developed Reserves (Volume)
29,799 
28,771 
33,370 
37,255 
Proved Undeveloped Reserve (Volume)
408 
238 
352 
1,222 
West Coast Region [Member] |
Natural Gas (Mmcf) [Member]
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
Proved Developed and Undeveloped Reserves
43,124 
49,346 
58,822 
 
Extensions and Discoveries
 
Revisions of Previous Estimates
6,369 
(3,132)
(6,317)
 
Production Volume
(2,995)
(3,090)
(3,159)
 
Sales of Minerals in Place
 
Proved Developed and Undeveloped Reserves
46,506 
43,124 
49,346 
 
Proved Developed Reserves (Volume)
46,506 
43,124 
49,346 
57,907 
Proved Undeveloped Reserve (Volume)
915 
West Coast Region [Member] |
Oil Mbbl [Member]
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
Proved Developed and Undeveloped Reserves
28,936 
33,502 
38,224 
 
Extensions and Discoveries
674 
530 
533 
 
Revisions of Previous Estimates
3,305 
(2,201)
(2,251)
 
Production Volume
(2,736)
(2,895)
(3,004)
 
Sales of Minerals in Place
 
 
Proved Developed and Undeveloped Reserves
30,179 
28,936 
33,502 
 
Proved Developed Reserves (Volume)
29,771 
28,698 
33,150 
37,002 
Proved Undeveloped Reserve (Volume)
408 
238 
352 
1,222 
Appalachian Region [Member] |
Natural Gas (Mmcf) [Member]
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
Proved Developed and Undeveloped Reserves
1,631,451 
2,092,782 
1,624,062 
 
Extensions and Discoveries
386,649 1
185,347 1
633,360 1
 
Revisions of Previous Estimates
84,480 
(245,029)
(28,124)
 
Production Volume
(154,093)2
(140,457)2
(136,404)2
 
Sales of Minerals in Place
(21,873)
(261,192)
(112)
 
Proved Developed and Undeveloped Reserves
1,926,614 
1,631,451 
2,092,782 
 
Proved Developed Reserves (Volume)
1,316,596 
1,089,492 
1,267,498 
1,119,901 
Proved Undeveloped Reserve (Volume)
610,018 
541,959 
825,284 
504,161 
Appalachian Region [Member] |
Oil Mbbl [Member]
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
Proved Developed and Undeveloped Reserves
73 
220 
253 
 
Extensions and Discoveries
 
Revisions of Previous Estimates
(12)
(46)
(3)
 
Production Volume
(4)
(28)
(30)
 
Sales of Minerals in Place
(29)
73 
 
 
Proved Developed and Undeveloped Reserves
28 
73 
220 
 
Proved Developed Reserves (Volume)
28 
73 
220 
253 
Proved Undeveloped Reserve (Volume)
Marcellus Shale Fields [Member]
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
Proved Undeveloped Reserve (Volume)
456,000,000,000 
542,000,000,000 
825,000,000,000 
 
Marcellus Shale Fields [Member] |
Natural Gas (Mmcf) [Member]
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
Extensions and Discoveries
181,000 
179,000 
598,000 
 
Production Volume
(145,452)
(135,598)
(130,291)
 
Percentage exceeding total reserve of production in proved developed and undeveloped reserves
15.00% 
 
 
 
Supplementary Information For Oil And Gas Producing Activities (Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves) (Details) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
Sep. 30, 2014
Supplementary Information For Oil And Gas Producing Activities Unaudited [Abstract]
 
 
 
 
Future Cash Inflows
$ 6,144,317 
$ 3,768,463 
$ 6,916,775 
 
Future Production Costs
2,378,262 
1,994,916 
2,854,142 
 
Future Development Costs
411,578 
375,152 
761,922 
 
Future Income Tax Expense at Applicable Statutory Rate
1,160,469 
303,397 
1,117,433 
 
Future Net Cash Flows
2,194,008 
1,094,998 
2,183,278 
 
10% Annual Discount for Estimated Timing of Cash Flows
1,080,962 
452,470 
860,244 
 
Standardized Measure of Discounted Future Net Cash Flows
$ 1,113,046 
$ 642,528 
$ 1,323,034 
$ 2,066,878 
Supplementary Information For Oil And Gas Producing Activities (Principal Sources Of Change In The Standardized Measure Of Discounted Future Net Cash Flows) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
Supplementary Information For Oil And Gas Producing Activities Unaudited [Abstract]
 
 
 
Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year
$ 642,528 
$ 1,323,034 
$ 2,066,878 
Sales, Net of Production Costs
(345,075)
(218,444)
(318,753)
Net Changes in Prices, Net of Production Costs
828,187 
(1,066,593)
(1,752,843)
Extensions and Discoveries
170,500 
47,742 
266,159 
Changes in Estimated Future Development Costs
8,816 
143,752 
164,510 
Sales of Minerals in Place
(9,849)
(95,849)
(1)
Previously Estimated Development Costs Incurred
101,134 
92,840 
161,833 
Net Change in Income Taxes at Applicable Statutory Rate
(393,353)
387,739 
545,442 
Revisions of Previous Quantity Estimates
39,078 
6,202 
(16,573)
Accretion of Discount and Other
71,080 
22,105 
206,382 
Standardized Measure of Discounted Future Net Cash Flows at End of Year
$ 1,113,046 
$ 642,528 
$ 1,323,034 
Valuation And Qualifying Accounts (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2015
Valuation and Qualifying Accounts [Abstract]
 
 
 
Balance at Beginning of Period
$ 21,109 
$ 29,029 
$ 31,811 
Additions Charged to Costs and Expenses
6,301 
6,819 
9,316 
Additions Charged to Other Accounts
1,774 1
1,521 1
2,585 1
Deductions
6,658 2
16,260 2
14,683 2
Balance at End of Period
$ 22,526 
$ 21,109 
$ 29,029