NATIONAL FUEL GAS CO, 10-K filed on 11/15/2019
Annual Report
v3.19.3
Document And Entity Information - USD ($)
12 Months Ended
Sep. 30, 2019
Oct. 31, 2019
Mar. 31, 2019
Cover page.      
Amendment Flag false    
Current Fiscal Year End Date --09-30    
Document Annual Report true    
Document Fiscal Period Focus FY    
Document Fiscal Year Focus 2019    
Document Period End Date Sep. 30, 2019    
Documents Incorporated by Reference Portions of the registrant’s definitive Proxy Statement for its 2020 Annual Meeting of Stockholders, to be filed with the Securities and Exchange Commission within 120 days of September 30, 2019, are incorporated by reference into Part III of this report.    
Document Transition Report false    
Document Type 10-K    
Entity Address, Address Line One 6363 Main Street    
Entity Address, City or Town Williamsville,    
Entity Address, State or Province NY    
Entity Address, Postal Zip Code 14221    
Entity Central Index Key 0000070145    
Entity Common Stock, Shares Outstanding   86,324,767  
Entity Current Reporting Status Yes    
Entity Emerging Growth Company false    
Entity File Number 1-3880    
Entity Filer Category Large Accelerated Filer    
Entity Incorporation, State or Country Code NJ    
Entity Interactive Data Current Yes    
Entity Public Float     $ 5,152,011,000
Entity Listing, Par Value Per Share $ 1.00    
Entity Registrant Name National Fuel Gas Company    
Entity Shell Company false    
Entity Small Business false    
Entity Tax Identification Number 13-1086010    
Entity Voluntary Filers No    
Entity Well-known Seasoned Issuer Yes    
City Area Code 716    
Local Phone Number 857-7000    
Title of 12(b) Security Common Stock, par value $1.00 per share    
Security Exchange Name NYSE    
Trading Symbol NFG    
v3.19.3
Consolidated Statements Of Income And Earnings Reinvested In The Business - USD ($)
$ in Thousands
12 Months Ended
Sep. 30, 2019
Sep. 30, 2018
Sep. 30, 2017
INCOME      
Operating Revenues $ 1,693,332 $ 1,592,668 $ 1,579,881
Operating Expenses:      
Property, Franchise and Other Taxes 88,886 84,393 84,995
Depreciation, Depletion and Amortization 275,660 240,961 224,195
Total Operating Expenses 1,181,523 1,072,945 986,103
Operating Income 511,809 519,723 593,778
Other Income (Expense):      
Other Income (Deductions) (15,542) (21,174) (29,777)
Interest Expense on Long-Term Debt (101,614) (110,946) (116,471)
Other Interest Expense (5,142) (3,576) (3,366)
Income Before Income Taxes 389,511 384,027 444,164
Income Tax Expense (Benefit) 85,221 (7,494) 160,682
Net Income Available for Common Stock 304,290 391,521 283,482
EARNINGS REINVESTED IN THE BUSINESS      
Balance at Beginning of Year 1,098,900 851,669 676,361
Beginning Retained Earnings Unappropriated And Current Period Net Income 1,403,190 1,243,190 959,843
Dividends on Common Stock (148,432) (144,290) (140,090)
Balance at End of Year $ 1,272,601 $ 1,098,900 $ 851,669
Earnings Per Common Share, Basic:      
Net Income Available for Common Stock (in dollars per share) $ 3.53 $ 4.56 $ 3.32
Earnings Per Common Share, Diluted:      
Net Income Available for Common Stock (in dollars per share) $ 3.51 $ 4.53 $ 3.30
Weighted Average Number of Shares Outstanding:      
Used in Basic Calculation 86,235,550 85,830,597 85,364,929
Used in Diluted Calculation 86,773,259 86,439,698 86,021,386
Utility and Energy Marketing [Member]      
INCOME      
Operating Revenues $ 860,985 $ 812,474 $ 755,485
Operating Expenses:      
Operation and Maintenance 171,472 168,885 169,731
Exploration and Production and Other [Member]      
INCOME      
Operating Revenues 636,528 569,808 617,666
Operating Expenses:      
Operation and Maintenance 147,457 139,546 141,010
Pipeline and Storage and Gathering [Member]      
INCOME      
Operating Revenues 195,819 210,386 206,730
Operating Expenses:      
Operation and Maintenance 111,783 101,338 90,918
Purchased Gas [Member]      
Operating Expenses:      
Purchased Gas 386,265 337,822 275,254
Guidance for Recognition and Measurement of Financial Assets and Liabilities [Member]      
EARNINGS REINVESTED IN THE BUSINESS      
Cumulative Effect of Adoption of Authoritative Guidance 7,437 0 0
Guidance for Reclassification of Stranded Tax Effects [Member]      
EARNINGS REINVESTED IN THE BUSINESS      
Cumulative Effect of Adoption of Authoritative Guidance 10,406 0 0
Guidance for Stock Based Compensation [Member]      
EARNINGS REINVESTED IN THE BUSINESS      
Cumulative Effect of Adoption of Authoritative Guidance $ 0 $ 0 $ 31,916
v3.19.3
Consolidated Statements Of Comprehensive Income - USD ($)
$ in Thousands
12 Months Ended
Sep. 30, 2019
Sep. 30, 2018
Sep. 30, 2017
Statement of Comprehensive Income [Abstract]      
Net Income Available for Common Stock $ 304,290 $ 391,521 $ 283,482
Other Comprehensive Income (Loss), Before Tax:      
Increase (Decrease) in the Funded Status of the Pension and Other Post-Retirement Benefit Plans (44,089) 6,225 15,661
Reclassification Adjustment for Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans 7,332 9,704 13,433
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period 0 132 4,008
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period 79,301 (74,103) 5,347
Reclassification Adjustment for Realized (Gains) Losses on Securities Available for Sale in Net Income 0 (430) (1,575)
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income 5,464 1,189 (81,605)
Reclassification Adjustment for the Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities to Earnings Reinvested in the Business (11,738) 0 0
Other Comprehensive Income (Loss), Before Tax 36,270 (57,283) (44,731)
Income Tax Expense (Benefit) Related to the Increase (Decrease) in the Funded Status of the Pension and Other Post-Retirement Benefit Plans (10,473) 1,582 6,175
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 1,698 2,437 4,929
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period 0 (15) 1,505
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period 20,619 (22,547) 2,009
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Securities Available for Sale in Net Income 0 (158) (580)
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income 2,726 (955) (34,286)
Reclassification Adjustment for Income Tax Benefit (Expense) on the Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities to Earnings Reinvested in the Business (4,301) 0 0
Reclassification Adjustment for Stranded Tax Effects Related to the 2017 Tax Reform Act to Earnings Reinvested in the Business 10,406 0 0
Income Taxes - Net 20,675 (19,656) (20,248)
Other Comprehensive Income (Loss) 15,595 (37,627) (24,483)
Comprehensive Income $ 319,885 $ 353,894 $ 258,999
v3.19.3
Consolidated Balance Sheets - USD ($)
$ in Thousands
Sep. 30, 2019
Sep. 30, 2018
ASSETS    
Property, Plant and Equipment $ 11,204,838 $ 10,439,839
Less - Accumulated Depreciation, Depletion and Amortization 5,695,328 5,462,696
Property, Plant and Equipment, Net, Total 5,509,510 4,977,143
Current Assets    
Cash and Temporary Cash Investments 20,428 229,606
Hedging Collateral Deposits [1] 6,832 3,441
Receivables - Net of Allowance for Uncollectible Accounts of $25,788 and $24,537, Respectively 139,956 141,498
Unbilled Revenue 18,758 24,182
Gas Stored Underground 36,632 37,813
Materials and Supplies - at average cost 40,717 35,823
Unrecovered Purchased Gas Costs 2,246 4,204
Other Current Assets 97,054 68,024
Total Current Assets 362,623 544,591
Other Assets    
Recoverable Future Taxes 115,197 115,460
Unamortized Debt Expense 14,005 15,975
Other Regulatory Assets 167,320 112,918
Deferred Charges 33,843 40,025
Other Investments 144,917 132,545
Goodwill 5,476 5,476
Prepaid Post-Retirement Benefit Costs 60,517 82,733
Fair Value of Derivative Financial Instruments 48,669 9,518
Other 80 102
Total Other Assets 590,024 514,752
Total Assets 6,462,157 6,036,486
Capitalization:    
Common Stock, $1 Par Value Authorized - 200,000,000 Shares; Issued and Outstanding - 86,315,287 Shares and 85,956,814 Shares, Respectively 86,315 85,957
Paid In Capital 832,264 820,223
Earnings Reinvested in the Business 1,272,601 1,098,900
Accumulated Other Comprehensive Loss (52,155) (67,750)
Total Comprehensive Shareholders' Equity 2,139,025 1,937,330
Long-term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs 2,133,718 2,131,365
Total Capitalization 4,272,743 4,068,695
Current and Accrued Liabilities    
Notes Payable to Banks and Commercial Paper 55,200 0
Current Portion of Long-Term Debt [2] 0 0
Accounts Payable 132,208 160,031
Amounts Payable to Customers 4,017 3,394
Dividends Payable 37,547 36,532
Interest Payable on Long-Term Debt 18,508 19,062
Customer Advances 13,044 13,609
Customer Security Deposits 16,210 25,703
Other Accruals and Current Liabilities 139,600 132,693
Fair Value of Derivative Financial Instruments 5,574 49,036
Total Current and Accrued Liabilities 421,908 440,060
Deferred Credits    
Deferred Income Taxes 653,382 512,686
Taxes Refundable to Customers 366,503 370,628
Cost of Removal Regulatory Liability 221,699 212,311
Other Regulatory Liabilities 142,367 146,743
Pension and Other Post-Retirement Liabilities 133,729 66,103
Asset Retirement Obligations 127,458 108,235
Other Deferred Credits 122,368 111,025
Total Deferred Credits 1,767,506 1,527,731
Commitments and Contingencies (Note J) 0 0
Total Capitalization and Liabilities $ 6,462,157 $ 6,036,486
[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.
[2]
None of the Company's long-term debt at September 30, 2019 and 2018 will mature within the following twelve-month period.
v3.19.3
Consolidated Balance Sheets (Parenthetical) - USD ($)
$ in Thousands
Sep. 30, 2019
Sep. 30, 2018
Statement of Financial Position [Abstract]    
Receivables, Allowance for Uncollectible Accounts $ 25,788 $ 24,537
Common Stock, Par Value $ 1 $ 1
Common Stock, Shares Authorized 200,000,000 200,000,000
Common Stock, Shares Issued 86,315,287 85,956,814
Common Stock, Shares Outstanding 86,315,287 85,956,814
v3.19.3
Consolidated Statements Of Cash Flows - USD ($)
$ in Thousands
12 Months Ended
Sep. 30, 2019
Sep. 30, 2018
Sep. 30, 2017
Operating Activities      
Net Income Available for Common Stock $ 304,290 $ 391,521 $ 283,482
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:      
Depreciation, Depletion and Amortization 275,660 240,961 224,195
Deferred Income Taxes 122,265 (18,153) 117,975
Stock-Based Compensation 21,186 15,762 12,262
Other 8,608 16,133 16,476
Change in:      
Receivables and Unbilled Revenue 6,379 (30,882) (3,380)
Gas Stored Underground and Materials and Supplies (3,713) (4,021) (1,417)
Unrecovered Purchased Gas Costs 1,958 419 (2,183)
Other Current Assets (29,030) (16,519) 7,849
Accounts Payable (24,770) 17,962 17,192
Amounts Payable to Customers 623 3,394 (19,537)
Customer Advances (565) (2,092) 939
Customer Security Deposits (9,493) 5,331 4,353
Other Accruals and Current Liabilities 10,992 3,865 27,004
Other Assets 5,115 (9,556) (2,885)
Other Liabilities 4,978 1,178 2,183
Net Cash Provided by Operating Activities 694,483 615,303 684,508
Investing Activities      
Capital Expenditures (788,938) (584,004) (450,335)
Net Proceeds from Sale of Oil and Gas Producing Properties 0 55,506 26,554
Other (10,237) (389) 1,216
Net Cash Used in Investing Activities (799,175) (528,887) (422,565)
Financing Activities      
Change in Notes Payable to Banks and Commercial Paper 55,200 0 0
Net Proceeds from Issuance of Long-Term Debt 0 295,020 295,151
Reduction of Long-Term Debt 0 (566,512) 0
Net Repurchases of Common Stock (8,877)    
Net Proceeds from Issuance of Common Stock   4,110 7,784
Dividends Paid on Common Stock (147,418) (143,258) (139,063)
Net Cash Provided by (Used in) Financing Activities (101,095) (410,640) 163,872
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash (205,787) (324,224) 425,815
Cash, Cash Equivalents and Restricted Cash At Beginning of Year 233,047 557,271 131,456
Cash, Cash Equivalents and Restricted Cash At End of Year 27,260 233,047 557,271
Supplemental Disclosure of Cash Flow Information      
Cash Paid for Interest 102,920 126,079 116,894
Cash Refunded for Income Taxes (17,342)    
Cash Paid for Income Taxes   31,771 34,826
Supplemental Disclosure of Cash Flow Information, Non-Cash Investing Activities      
Non-Cash Capital Expenditures $ 81,121 $ 88,813 $ 72,216
v3.19.3
Summary Of Significant Accounting Policies
12 Months Ended
Sep. 30, 2019
Accounting Policies [Abstract]  
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.
Reclassifications
In November 2016, the FASB issued authoritative guidance related to the presentation of restricted cash on the statement of cash flows. The new guidance requires restricted cash and cash equivalents be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows, and requires disclosure of how cash and cash equivalents on the statement of cash flows reconciles to the balance sheet. The Company considers Hedging Collateral Deposits to be restricted cash. The Company adopted this guidance effective October 1, 2018 on a retrospective basis. As a result, prior periods have been reclassified to conform to the current year presentation. Additional discussion is provided below at Consolidated Statement of Cash Flows.
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 is eligible to be capitalized as part of the cost of inventory or property, plant and equipment while the other components of net periodic pension cost and net periodic postretirement benefit cost are generally not eligible for capitalization, unless allowed by a regulator. The Company adopted this guidance effective October 1, 2018. The Company applied the guidance retrospectively for the pension and postretirement benefit costs using amounts disclosed in prior period financial statement notes as estimates for the reclassifications in accordance with a practical expedient allowed under the guidance. For the years ended September 30, 2018 and September 30, 2017, Operating Income increased $32.6 million and $40.9 million, respectively, and Other Income (Deductions) decreased by the same amounts as a result of the reclassifications. For the year ended September 30, 2019, Other Income (Deductions) includes $27.3 million of pension and postretirement benefit costs.
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 D — Regulatory Matters for further discussion.

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 D — 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 March 31st, and applied to customer bills annually, beginning July 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. The Company's capitalized costs relating to oil and gas producing activities, net of accumulated depreciation, depletion and amortization, were $1.7 billion and $1.3 billion at September 30, 2019 and 2018, respectively. 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 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, 2019, the ceiling exceeded the book value of the oil and gas properties by $381.2 million. In adjusting estimated future net cash flows for hedging under the ceiling test at September 30, 2019, 2018 and 2017, estimated future net cash flows were decreased by $17.7 million, decreased by $25.1 million and increased by $30.5 million, respectively.
The Company entered into a purchase and sale agreement to sell its oil and gas properties in the Sespe Field area of Ventura County, California in October 2017 for $43.0 million.  The Company completed the sale on May 1, 2018, effective as of October 1, 2017, receiving net proceeds of $38.2 million (included in Net Proceeds from Sale of Oil and Gas Producing Properties on the Consolidated Statement of Cash Flows for the year ended September 30, 2018).  The net proceeds received by the Company were adjusted for production revenue and production expenses retained by the Company between the effective date of the sale and the closing date, resulting in lower proceeds from sale at the closing date. The divestiture of the Company’s oil and gas properties in the Sespe Field reflects continuing efforts to focus West Coast development activities in the San Joaquin basin, particularly at the Midway Sunset field in Kern County, California. Under the full cost method of accounting for oil and gas properties, the sale proceeds were accounted for as a reduction of capitalized costs.  Since the disposition did not significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center, the Company did not record any gain or loss from this sale.
The Company also sold certain properties under a joint development agreement with IOG CRV - Marcellus, LLC that provided proceeds of $17.3 million and $26.6 million in fiscal 2018 and fiscal 2017, respectively. These proceeds were accounted for as a reduction of capitalized costs and are included in Net Proceeds from Sale of Oil and Gas Producing Properties on the Consolidated Statement of Cash Flows for fiscal 2018 and fiscal 2017.
The principal assets of the Utility, Pipeline and Storage and Gathering 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. Depreciation, depletion and amortization expense for oil and gas properties was $149.9 million, $119.9 million and $108.5 million for the years ended September 30, 2019, 2018 and 2017, respectively. 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
 
2019
 
2018
 
(Thousands)
Exploration and Production
$
5,747,731

 
$
5,222,037

Pipeline and Storage
2,191,166

 
2,110,714

Gathering
577,021

 
527,188

Utility
2,159,841

 
2,104,437

All Other and Corporate
112,857

 
112,295

 
$
10,788,616

 
$
10,076,671


Average depreciation, depletion and amortization rates are as follows:
 
Year Ended September 30
 
2019
 
2018
 
2017
Exploration and Production, per Mcfe(1)
$
0.73

 
$
0.70

 
$
0.65

Pipeline and Storage
2.2
%
 
2.2
%
 
2.2
%
Gathering
3.6
%
 
3.4
%
 
3.4
%
Utility
2.7
%
 
2.8
%
 
2.8
%
All Other and Corporate
1.8
%
 
2.4
%
 
1.5
%
 
(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 $0.71, $0.67 and $0.63 per Mcfe of production in 2019, 2018 and 2017, respectively.
Goodwill
The Company has recognized goodwill of $5.5 million as of September 30, 2019 and 2018 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, 2019, 2018 and 2017, 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
The Company uses a variety of derivative financial instruments to manage a portion of the market risk associated with fluctuations in the price of gas and 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 G — 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 or purchased gas expense on the Consolidated
Statements of Income. Reference is made to Note H — 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 H — 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, 2019, 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, 2019
 
 
 
 
 
 
 
Balance at October 1, 2018
$
(28,611
)
 
$
7,437

 
$
(46,576
)
 
$
(67,750
)
Other Comprehensive Gains and Losses Before Reclassifications
58,682

 

 
(33,616
)
 
25,066

Amounts Reclassified From Other Comprehensive Income
2,738

 

 
5,634

 
8,372

Reclassification Adjustment for the Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities

 
(7,437
)
 

 
(7,437
)
Reclassification of Stranded Tax Effects Related to the 2017 Tax Reform Act
1,866

 

 
(12,272
)
 
(10,406
)
Balance at September 30, 2019
$
34,675

 
$

 
$
(86,830
)
 
$
(52,155
)
Year Ended September 30, 2018
 
 
 
 
 
 
 
Balance at October 1, 2017
$
20,801

 
$
7,562

 
$
(58,486
)
 
$
(30,123
)
Other Comprehensive Gains and Losses Before Reclassifications
(51,556
)
 
147

 
4,643

 
(46,766
)
Amounts Reclassified From Other Comprehensive Loss
2,144

 
(272
)
 
7,267

 
9,139

Balance at September 30, 2018
$
(28,611
)
 
$
7,437

 
$
(46,576
)
 
$
(67,750
)

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 $1.0 million at both September 30, 2019 and 2018. The total amount for accumulated losses was $85.8 million and $45.6 million at September 30, 2019 and 2018, respectively.
In February 2018, the FASB issued authoritative guidance that allows an entity to elect a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the
2017 Tax Reform Act and requires certain disclosures about stranded tax effects. The Company adopted this authoritative guidance effective January 1, 2019 and recorded a cumulative effect adjustment related to deferred income taxes associated with hedging activities and pension and post-retirement benefit obligations during the quarter ended March 31, 2019 to increase retained earnings by $10.4 million and decrease accumulated other comprehensive income by the same amount.
In January 2016, the FASB issued authoritative guidance regarding the recognition and measurement of financial assets and liabilities. The authoritative guidance primarily affects the accounting for equity investments and the presentation and disclosure requirements for financial instruments. All equity investments in unconsolidated entities will be measured at fair value through earnings rather than through accumulated other comprehensive income. The Company adopted this authoritative guidance effective October 1, 2018 and, as called for by the modified retrospective method of adoption, recorded a cumulative effect adjustment during the quarter ended December 31, 2018 to increase retained earnings by $7.4 million and decrease accumulated other comprehensive income by the same amount.
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, 2019 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 is Presented
 
 
2019
 
2018
 
 
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
 
 
 
 
 
 
Commodity Contracts
 

($3,460
)
 

$423

 
Operating Revenues
Commodity Contracts
 
(1,182
)
 
952

 
Purchased Gas
Foreign Currency Contracts
 
(822
)
 
(2,564
)
 
Operating Revenues
Gains (Losses) on Securities Available for Sale
 

 
430

 
Other Income (Deductions)
Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans:
 
 
 
 
 
 
Prior Service Cost
 
(264
)
 
(258
)
 
(1)
Net Actuarial Loss
 
(7,068
)
 
(9,446
)
 
(1)
 
 
(12,796
)
 
(10,463
)
 
Total Before Income Tax
 
 
4,424

 
1,324

 
Income Tax Expense
 
 

($8,372
)
 

($9,139
)
 
Net of Tax
 
(1)
These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost. Refer to Note I — Retirement Plan and Other Post-Retirement Benefits for additional details.
Gas Stored Underground 
In the Utility segment, gas stored underground in the amount of $29.6 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
2019, including transportation costs, the current cost of replacing this inventory of gas stored underground exceeded the amount stated on a LIFO basis by approximately $19.8 million at September 30, 2019. All other gas stored underground, which is recorded by NFR (included in the All Other category), 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, 2019, the remaining weighted average amortization period for such costs was approximately 7 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 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 (Deductions).
Consolidated Statement of Cash Flows
The components, as reported on the Company's Consolidated Balance Sheets, of the total cash, cash equivalents, and restricted cash presented on the Statement of Cash Flows are as follows (in thousands):
 
Year Ended September 30
 
2019
 
2018
 
2017
 
2016
 
 
Cash and Temporary Cash Investments
$
20,428

 
$
229,606

 
$
555,530

 
$
129,972

Hedging Collateral Deposits
6,832

 
3,441

 
1,741

 
1,484

Cash, Cash Equivalents, and Restricted Cash
$
27,260

 
$
233,047

 
$
557,271

 
$
131,456


The Company considers all highly liquid debt instruments purchased with a maturity date of generally three months or less to be cash equivalents. The Company’s restricted cash is composed entirely of amounts reported as Hedging Collateral Deposits on the Consolidated Balance Sheets. Hedging Collateral Deposits 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 instruments liability or asset balances.
Other Current Assets
The components of the Company’s Other Current Assets are as follows: 
 
Year Ended September 30
 
2019
 
2018
 
(Thousands)
Prepayments
$
12,728

 
$
11,126

Prepaid Property and Other Taxes
14,361

 
14,088

Federal Income Taxes Receivable
42,388

 
22,457

State Income Taxes Receivable
8,579

 
8,822

Fair Values of Firm Commitments
7,538

 
1,739

Regulatory Assets
11,460

 
9,792

 
$
97,054

 
$
68,024


Other Accruals and Current Liabilities
The components of the Company’s Other Accruals and Current Liabilities are as follows:
 
Year Ended September 30
 
2019
 
2018
 
(Thousands)
Accrued Capital Expenditures
$
33,713

 
$
38,354

Regulatory Liabilities
50,332

 
57,425

Liability for Royalty and Working Interests
18,057

 
12,062

Non-Qualified Benefit Plan Liability
13,194

 
11,536

Other
24,304

 
13,316

 
$
139,600

 
$
132,693


Customer Advances
The Company, primarily in its Utility segment, has 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, 2019 and 2018, customers in the balanced billing programs had advanced excess funds of $13.0 million and $13.6 million, respectively.
Customer Security Deposits
The Company, primarily in its Utility and Pipeline and Storage 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, 2019 and 2018, the Company had received customer security deposits amounting to $16.2 million and $25.7 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 had outstanding were SARs, restricted stock units and performance shares. 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. SARs, restricted stock units and performance shares that are antidilutive are excluded from the calculation of diluted earnings per common share. There were 242,302 securities, 317,899 securities and 157,649 securities excluded as being antidilutive for the years ended September 30, 2019, 2018 and 2017, respectively.
Stock-Based Compensation
The Company has various stock award plans which provide or provided for the issuance of one or more of the following to key employees: SARs, incentive stock options, nonqualified stock options, 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. SARs and stock options under all plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no SAR or stock option 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 SARs and stock options. 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 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 nonperformance-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 nonperformance-based restricted stock units do not entitle the participants to dividend and voting rights. The accounting for performance based and nonperformance-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 F — Capitalization and Short-Term Borrowings under the heading “Stock Award Plans” for additional disclosures related to stock-based compensation awards for all plans.
New Authoritative Accounting and Financial Reporting Guidance
Leasing
In February 2016, the FASB issued authoritative guidance, which has subsequently been amended, requiring entities 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 entities to recognize on the balance sheet the assets and liabilities for the rights and obligations created by capital leases only while excluding operating leases from balance sheet recognition. The updated guidance provides entities with an optional transition method, which allows an entity to apply the new lease standard prospectively at the adoption date, elect not to reclassify comparable periods, and recognize a cumulative-effect adjustment to retained earnings in the period of adoption.
The Company adopted the new leases standard on October 1, 2019, using the optional transition method. Comparative periods, including disclosures relating to those periods, will not be restated. The Company also elected to apply the following practical expedients provided in the guidance:
1.
For contracts that commenced prior to and existed as of October 1, 2019, a package of practical expedients to not reassess whether a contract is or contains a lease, lease classification, and initial direct costs under the new leases standard
2.
An election not to apply the recognition requirements in the new leases standard to short-term leases (a lease that at commencement date has a lease term of twelve months or less)
3.
A practical expedient to not reassess certain land easements that existed prior to October 1, 2019; and
4.
A practical expedient that permits combining lease and non-lease components in a contract and accounting for the combination as a lease (elected by asset class).
The Company has completed its determination and evaluation of its population of existing lease contracts as of October 1, 2019, which include leases of office buildings and facilities, land for surface use, compressors and field equipment, and other leases. The new leases standard does not apply to leases to explore for or use minerals, oil or gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained. The Company has documented the nature and impact of technical issues and related accounting policy elections. The Company has also designed and implemented procedures and internal controls to ensure that contracts that are leases or contain lease components are appropriately accounted for under the authoritative guidance, including both new contracts and modifications to existing contracts.
The Company expects to recognize a right of use asset for operating leases and a corresponding operating lease liability on its Consolidated Balance Sheets of approximately $20.0 million, representing the present value of the minimum remaining payment obligations of existing lease contracts with lease terms greater than twelve months. The Company’s adoption did not require an adjustment to the opening balance of retained earnings. The Company does not expect the adoption of the new leases standard to have a material effect on its results of operations or cash flows. Additional disclosures will be required to describe the nature of the Company’s leases, significant assumptions and judgments, amounts recognized in the financial statements, maturity of lease liabilities, and accounting policy elections.
Hedging
In August 2017, the FASB issued authoritative guidance which changes the financial reporting of hedging relationships to better portray the economic results of an entity's risk management activities and to simplify the application of hedge accounting. The Company adopted this authoritative guidance effective October 1, 2019, recognizing a cumulative effect adjustment that decreased retained earnings by $1.0 million.
v3.19.3
Revenue from Contracts with Customers
12 Months Ended
Sep. 30, 2019
Revenue from Contract with Customer [Abstract]  
Revenue from Contracts with Customers Revenue from Contracts with Customers
The Company adopted authoritative guidance regarding revenue recognition on October 1, 2018 using the modified retrospective method of adoption for open contracts as of October 1, 2018. A cumulative effect adjustment to retained earnings was not necessary since no revenue recognition differences were identified when comparing the revenue recognition criteria under the new authoritative guidance to the previous guidance. The Company records revenue related to its derivative financial instruments in the Exploration and Production segment as well as in its NFR operations (included in the All Other category). The Company also records revenue related to alternative revenue programs in its Utility segment. Revenue related to derivative financial instruments and alternative revenue programs are excluded from the scope of the new authoritative guidance since they are accounted for under other existing accounting guidance.
The following table provides a disaggregation of the Company's revenues for the year ended September 30, 2019, presented by type of service from each reportable segment.
 
Year Ended September 30, 2019
Revenues by Type of Service
Exploration
and
Production
 
Pipeline
and
Storage
 
Gathering
 
Utility
 
Total
Reportable
Segments
 
All
Other
 
Corporate
and
Intersegment
Eliminations
 
Total
Consolidated
 
(Thousands)
Production of Natural Gas
$
481,048

 
$

 
$

 
$

 
$
481,048

 
$

 
$

 
$
481,048

Production of Crude Oil
149,078

 

 

 

 
149,078

 

 

 
149,078

Natural Gas Processing
3,277

 

 

 

 
3,277

 

 

 
3,277

Natural Gas Gathering Service

 

 
127,064

 

 
127,064

 

 
(127,064
)
 

Natural Gas Transportation Service

 
209,184

 

 
119,253

 
328,437

 

 
(70,689
)
 
257,748

Natural Gas Storage Service

 
75,484

 

 

 
75,484

 

 
(32,488
)
 
42,996

Natural Gas Residential Sales

 

 

 
539,962

 
539,962

 

 

 
539,962

Natural Gas Commercial Sales

 

 

 
73,331

 
73,331

 

 

 
73,331

Natural Gas Industrial Sales

 

 

 
4,830

 
4,830

 

 

 
4,830

Natural Gas Marketing

 

 

 

 

 
143,627

 
(1,127
)
 
142,500

Other
1,609

 
3,615

 
11

 
(8,630
)
 
(3,395
)
 
3,424

 
(549
)
 
(520
)
Total Revenues from Contracts with Customers
635,012

 
288,283

 
127,075

 
728,746

 
1,779,116

 
147,051

 
(231,917
)
 
1,694,250

Alternative Revenue Programs

 

 

 
(1,304
)
 
(1,304
)
 

 

 
(1,304
)
Derivative Financial Instruments
(2,272
)
 

 

 

 
(2,272
)
 
2,658

 

 
386

Total Revenues
$
632,740

 
$
288,283

 
$
127,075

 
$
727,442

 
$
1,775,540

 
$
149,709

 
$
(231,917
)
 
$
1,693,332


Exploration and Production Segment Revenue
The Company’s Exploration and Production segment records revenue from the sale of the natural gas and oil that it produces and natural gas liquids (NGLs) processed based on entitlement, which means that revenue is recorded based on the actual amount of natural gas or oil that is delivered to a pipeline, or upon pick-up in the case of NGLs, and the Company’s ownership interest. Natural gas production occurs primarily in the Appalachian region of the United States and crude oil production occurs primarily in the West Coast region of the United States. 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 sales contracts generally require the Company to deliver a specific quantity of a commodity per day for a specific number of days at a price that is either fixed or variable and considers the delivery of each unit (MMBtu or Bbl) to be a separate performance obligation that is satisfied upon delivery.  
The transaction price for the sale of natural gas, oil and NGLs is contractually agreed upon based on prevailing market pricing (primarily tied to a market index with certain adjustments based on factors such as delivery location
and prevailing supply and demand conditions) or fixed pricing.  The Company allocates the transaction price to each performance obligation on the basis of the relative standalone selling price of each distinct unit sold. Revenue is recognized at a point in time when the transfer of the commodity occurs at the delivery point per the contract. The amount billable, as determined by the contracted quantity and price, indicates the value to the customer, and is used for revenue recognition purposes by the Exploration and Production segment as specified by the “invoice practical expedient” (the amount that the Exploration and Production segment has the right to invoice) under the authoritative guidance for revenue recognition. The contracts typically require payment within 30 days of the end of the calendar month in which the natural gas and oil is delivered, or picked up in the case of NGLs.
The Company uses derivative financial instruments to manage commodity price risk in the Exploration and Production segment related to sales of the natural gas and oil that it produces. Gains or losses on such derivative financial instruments are recorded as adjustments to revenue; however, they are not considered to be revenue from contracts with customers.
Pipeline and Storage Segment Revenue
The Company’s Pipeline and Storage segment records revenue for natural gas transportation and storage services in New York and Pennsylvania at tariff-based rates regulated by the FERC. Customers secure their own gas supply and the Pipeline and Storage segment provides transportation and/or storage services to move the customer-supplied gas to the intended location, including injections into or withdrawals from the storage field. This performance obligation is satisfied over time. The rate design for the Pipeline and Storage segment’s customers generally includes a combination of volumetric or commodity charges as well as monthly “fixed” charges (including charges commonly referred to as capacity charges, demand charges, or reservation charges). These types of fixed charges represent compensation for standing ready over the period of the month to deliver quantities of gas, regardless of whether the customer takes delivery of any quantity of gas. The performance obligation under these circumstances is satisfied based on the passage of time and meter reads, if applicable, which correlates to the period for which the charges are eligible to be invoiced. The amount billable, as determined by the meter read and the “fixed” monthly charge, indicates the value to the customer, and is used for revenue recognition purposes by the Pipeline and Storage segment as specified by the “invoice practical expedient” (the amount that the Pipeline and Storage segment has the right to invoice) under the authoritative guidance for revenue recognition. Customers are billed after the end of each calendar month, with payment typically due by the 25th day of the month in which the invoice is received.
The Company’s Pipeline and Storage segment expects to recognize the following revenue amounts in future periods related to “fixed” charges associated with remaining performance obligations for transportation and storage contracts: $162.0 million for fiscal 2020; $138.4 million for fiscal 2021; $115.1 million for fiscal 2022; $82.3 million for fiscal 2023; $72.9 million for fiscal 2024; and $297.6 million thereafter.
Gathering Segment Revenue
The Company’s Gathering segment provides gathering and processing services in the Appalachian region of Pennsylvania, primarily for Seneca. The Gathering segment’s primary performance obligation is to deliver gathered natural gas volumes from Seneca’s wells into interstate pipelines at contractually agreed upon per unit rates. This obligation is satisfied over time. The performance obligation is satisfied based on the passage of time and meter reads, which correlates to the period for which the charges are eligible to be invoiced. The amount billable, as determined by the meter read and the contracted volumetric rate, indicates the value to the customer, and is used for revenue recognition purposes by the Gathering segment as specified by the “invoice practical expedient” (the amount that the Gathering segment has the right to invoice) under the authoritative guidance for revenue recognition. Customers are billed after the end of each calendar month, with payment typically due by the 10th day after the invoice is received.
Utility Segment Revenue
The Company’s Utility segment records revenue for natural gas sales and natural gas transportation services in western New York and northwestern Pennsylvania at tariff-based rates regulated by the NYPSC and the PaPUC. Natural gas sales and transportation services are provided largely to residential, commercial and industrial customers. The Utility segment’s performance obligation to its customers is to deliver natural gas, an obligation which is satisfied over time. This obligation generally remains in effect as long as the customer consumes the natural gas provided by the Utility segment. The Utility segment recognizes revenue when it satisfies its performance obligation by delivering natural gas to the customer. Natural gas is delivered and consumed by the customer simultaneously. The satisfaction of the performance obligation is measured by the turn of the meter dial. The amount billable, as determined by the meter read and the tariff-based rate, indicates the value to the customer, and is used for revenue recognition purposes by the Utility segment as specified by the “invoice practical expedient” (the amount that the Utility segment has the right to invoice) under the authoritative guidance for revenue recognition. Since the Utility segment bills its customers in cycles having billing dates that do not generally coincide with the end of a calendar month, a receivable is recorded for natural gas delivered but not yet billed to customers based on an estimate of the amount of natural 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 Utility segment’s tariffs allow customers to utilize budget billing. In this situation, since the amount billed may differ from the amount of natural gas delivered to the customer in any given month, revenue is recognized monthly based on the amount of natural gas consumed. The differential between the amount billed and the amount consumed is recorded as a component of Receivables or Customer Advances on the Consolidated Balance Sheets. All receivables or advances related to budget billing are settled within one year.
Utility Segment Alternative Revenue Programs
As indicated in the revenue table shown above, the Company’s Utility segment has alternative revenue programs that are excluded from the scope of the new authoritative guidance regarding revenue recognition. The NYPSC has authorized alternative revenue programs that are designed to mitigate the impact that weather and conservation have on margin. The NYPSC has also authorized additional alternative revenue programs that adjust billings for the effects of broad external factors or to compensate the Company for demand-side management initiatives. These alternative revenue programs primarily allow the Company and customer to share in variances from imputed margins due to migration of transportation customers, allow for adjustments to the gas cost recovery mechanism for fluctuations in uncollectible expenses associated with gas costs, and allow the Company to pass on to customers costs associated with customer energy efficiency programs. In general, revenue is adjusted monthly for these programs and is collected from or passed back to customers within 24 months of the annual reconciliation period.
Energy Marketing Revenue
The Company’s energy marketing subsidiary, NFR (included in the All Other category), records revenue from natural gas sales in western and central New York and northwestern Pennsylvania. NFR's operations were previously reported as the Energy Marketing segment, however the Company is no longer reporting the energy marketing operations as a separate reportable segment. For further discussion of this change, refer to Note K — Business Segment Information. NFR's sales are provided largely to industrial, wholesale, commercial, public authority and residential customers. NFR’s performance obligation to its customers is to deliver natural gas, an obligation which is satisfied over time. This obligation generally remains in effect as long as the customer consumes the natural gas provided by NFR. NFR recognizes revenue when it satisfies its performance obligation by delivering natural gas to the customer. Natural gas is delivered and consumed by the customer simultaneously. The satisfaction of the performance obligation is measured by the turn of the meter dial. The amount billable, as determined by the meter read and the contracted or market based rate, indicates the value to the customer, and is used for revenue recognition purposes by NFR as specified by the “invoice practical expedient” (the amount that NFR has the right to invoice) under the authoritative guidance for revenue recognition. Since NFR bills its residential customers in
cycles having billing dates that do not generally coincide with the end of a calendar month, a receivable is recorded for natural gas delivered but not yet billed to customers based on an estimate of the amount of natural 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. NFR also allows customers to utilize budget billing. In this situation, since the amount billed may differ from the amount of natural gas delivered to the customer in any given month, revenue is recognized monthly based on the amount of natural gas consumed. The differential between the amount billed and the amount consumed is recorded as a component of Receivables or Customer Advances on the Consolidated Balance Sheets. All receivables or advances related to budget billing are settled within one year.
The Company uses derivative financial instruments to manage commodity price risk in its NFR operations related to the sale of natural gas to its customers. Gains or losses on such derivative financial instruments are recorded as adjustments to revenue; however, they are not considered to be revenue from contracts with customers.
v3.19.3
Asset Retirement Obligations
12 Months Ended
Sep. 30, 2019
Asset Retirement Obligation [Abstract]  
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). This obligation increased significantly during fiscal 2019 for this segment's California operations due to a statewide effort to increase the pace of plugging idle wells combined with more stringent state mandated plugging requirements.
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, services and other 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.
The following is a reconciliation of the change in the Company’s asset retirement obligations:
 
Year Ended September 30
 
2019
 
2018
 
2017
 
(Thousands)
Balance at Beginning of Year
$
108,235

 
$
106,395

 
$
112,330

Liabilities Incurred
4,122

 
5,597

 
2,963

Revisions of Estimates
16,693

 
(419
)
 
(10,578
)
Liabilities Settled
(7,670
)
 
(12,858
)
 
(4,967
)
Accretion Expense
6,078

 
9,520

 
6,647

Balance at End of Year
$
127,458

 
$
108,235

 
$
106,395


v3.19.3
Regulatory Matters
12 Months Ended
Sep. 30, 2019
Regulatory Assets and Liabilities, Other Disclosures [Abstract]  
Regulatory Matters Regulatory Matters
Regulatory Assets and Liabilities
The Company has recorded the following regulatory assets and liabilities:
 
At September 30
 
2019
 
2018
 
(Thousands)
Regulatory Assets(1):
 
 
 
Pension Costs(2) (Note I)
$
114,509

 
$
62,703

Post-Retirement Benefit Costs(2) (Note I)
18,236

 
11,160

Recoverable Future Taxes (Note E)
115,197

 
115,460

Environmental Site Remediation Costs(2) (Note J)
15,317

 
20,308

Asset Retirement Obligations(2) (Note C)
15,696

 
15,495

Unamortized Debt Expense (Note A)
14,005

 
15,975

Other(3)
15,022

 
13,044

Total Regulatory Assets
307,982

 
254,145

Less: Amounts Included in Other Current Assets
(11,460
)
 
(9,792
)
Total Long-Term Regulatory Assets
$
296,522

 
$
244,353

 
 
At September 30
 
2019
 
2018
 
(Thousands)
Regulatory Liabilities:
 
 
 
Cost of Removal Regulatory Liability
$
221,699

 
$
212,311

Taxes Refundable to Customers (Note E)
366,503

 
370,628

Post-Retirement Benefit Costs(4) (Note I)
126,577

 
134,387

Amounts Payable to Customers (See Regulatory Mechanisms in Note A)
4,017

 
3,394

Other(5)
66,122

 
69,781

Total Regulatory Liabilities
784,918

 
790,501

Less: Amounts included in Current and Accrued Liabilities
(54,349
)
 
(60,819
)
Total Long-Term Regulatory Liabilities
$
730,569

 
$
729,682

 
(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)
$11,460 and $9,792 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2019 and 2018, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $3,562 and $3,252 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2019 and 2018, respectively.
(4)
Included in Other Regulatory Liabilities on the Consolidated Balance Sheets.
(5)
$50,332 and $57,425 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2019 and 2018, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $15,790 and $12,356 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2019 and 2018, 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 C — 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.
New York Jurisdiction
Distribution Corporation's current delivery rates in its New York jurisdiction were approved by the NYPSC in an order issued on April 20, 2017 with rates becoming effective May 1, 2017. The order provided for a return on equity of 8.7%. The order also directed the implementation of an earnings sharing mechanism to be in place beginning on April 1, 2018.
Pennsylvania Jurisdiction
Distribution Corporation’s Pennsylvania jurisdiction delivery rates are being charged to customers in accordance with a rate settlement approved by the PaPUC. The rate settlement does not specify any requirement to file a future rate case.
FERC Jurisdiction
Supply Corporation filed a Section 4 rate case on July 31, 2019 proposing rate increases to be effective September 1, 2019. The proposed rates reflect an annual cost of service of $295.4 million, a rate base of $970.8 million and a proposed cost of equity of 15%. The FERC has accepted the filed rates and suspended the effective date of the increases until February 1, 2020, when the rates will be made effective, subject to refund. If the rates finally approved at the end of the proceeding exceed the rates that were in effect at July 31, 2019, but are less than rates put into effect subject to refund on February 1, 2020, Supply Corporation would be required to refund the difference between the rates collected subject to refund and the final approved rates, with interest at the FERC-approved rate. If the rates approved at the end of the proceeding are lower than the rates in effect at July 31, 2019,
such lower rates will become effective prospectively from the date of the applicable FERC order, and refunds with interest will be limited to the difference between the rates collected subject to refund and the rates in effect at July 31, 2019. The FERC also terminated the proceeding in which Supply Corporation filed its Form 501-G, addressing the impact of the 2017 Tax Reform Act. Refer to Note E — Income Taxes for further discussion of the 2017 Tax Reform Act.
Empire's recent rate settlement, approved May 3, 2019 requires a Section 4 rate case filing no later than May 1, 2025. Empire has no rate case currently on file.
v3.19.3
Income Taxes
12 Months Ended
Sep. 30, 2019
Income Tax Disclosure [Abstract]  
Income Taxes Income Taxes
On December 22, 2017, federal tax legislation referred to as the “Tax Cuts and Jobs Act” (the 2017 Tax Reform Act) was enacted. The 2017 Tax Reform Act significantly changed the taxation of business entities and includes a reduction in the corporate federal income tax rate from 35% to a blended 24.5% for fiscal 2018 and 21% for fiscal 2019 and beyond. The changes had a material impact on the financial statements in the year ended September 30, 2018. The Company’s deferred income taxes were remeasured based upon the new tax rates. For the non-rate regulated activities through the year ended September 30, 2018, the change in beginning of the year deferred income taxes of $103.5 million was recorded as a reduction to income tax expense. For the Company's rate regulated activities, the reduction in deferred income taxes of $336.7 million was recorded as a decrease to Recoverable Future Taxes of $65.7 million and an increase to Taxes Refundable to Customers of $271.0 million. The 2017 Tax Reform Act includes provisions that stipulate how these excess deferred taxes are to be passed back to customers for certain accelerated tax depreciation benefits. Potential refunds of other deferred income taxes will be determined by the federal and state regulatory agencies.
The 2017 Tax Reform Act also repealed the corporate alternative minimum tax (AMT) and provides that the Company’s existing AMT credit carryovers are refundable, if not utilized to reduce tax, beginning in fiscal 2019. As of September 30, 2018, the Company had $85.0 million of AMT credit carryovers that are expected to be refunded between fiscal 2020 and fiscal 2023, if not previously utilized. During fiscal 2018, the Department of Treasury indicated that a portion of the refundable AMT credit carryovers would be subject to sequestration. Accordingly, the Company recorded a $5.0 million valuation allowance related to this sequestration. During the quarter ended December 31, 2018, the Office of Management and Budget determined that these AMT refunds would not be subject to sequestration. As such, the Company has removed the valuation allowance. These amounts are recorded in Deferred Income Taxes and will be reclassified to a receivable when the amounts are expected to be realized in cash. As of September 30, 2019, $42.5 million of AMT credit refunds are recorded as a receivable in Other Current Assets.
The SEC issued guidance in Staff Accounting Bulletin 118 (SAB 118) which provides for up to a one year period (the measurement period) in which to complete the required analysis and income tax accounting for the 2017 Tax Reform Act. Based upon the available guidance, the Company has completed the remeasurement of deferred income taxes as of December 31, 2018. Any subsequent guidance or clarification related to the 2017 Tax Reform Act will be accounted for in the period issued.
The components of federal and state income taxes included in the Consolidated Statements of Income are as follows:
 
Year Ended September 30
 
2019
 
2018
 
2017
 
(Thousands)
Current Income Taxes —
 
 
 
 
 
Federal
$
(41,645
)
 
$
2,025

 
$
32,034

State
4,601

 
8,634

 
10,673

Deferred Income Taxes —
 
 
 
 
 
Federal
98,514

 
(38,927
)
 
103,046

State
23,751

 
20,774

 
14,929

 
85,221

 
(7,494
)
 
160,682

Deferred Investment Tax Credit
(91
)
 
(105
)
 
(173
)
Total Income Taxes
$
85,130

 
$
(7,599
)
 
$
160,509

Presented as Follows:
 
 
 
 
 
Other (Income) Deductions
$
(91
)
 
$
(105
)
 
$
(173
)
Income Tax Expense (Benefit)
85,221

 
(7,494
)
 
160,682

Total Income Taxes
$
85,130

 
$
(7,599
)
 
$
160,509


Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income before income taxes. The following is a reconciliation of this difference:
 
Year Ended September 30
 
2019
 
2018
 
2017
 
(Thousands)
U.S. Income Before Income Taxes
$
389,420

 
$
383,922

 
$
443,991

Income Tax Expense, Computed at
U.S. Federal Statutory Rate(1)
$
81,778

 
$
94,061

 
$
155,397

State Income Tax Expense(2)
22,397

 
22,203

 
16,641

Federal Tax Credits
(7,361
)
 
(6,576
)
 
(6,679
)
Amortization of Excess Deferred Federal Income Taxes(3)
(5,036
)
 
(3,236
)
 

Impact of 2017 Tax Reform Act(4)
(5,000
)
 
(112,598
)
 

Miscellaneous
(1,648
)
 
(1,453
)
 
(4,850
)
Total Income Taxes
$
85,130

 
$
(7,599
)
 
$
160,509


 
(1)
For fiscal 2019, the statutory rate of 21% was utilized. For fiscal 2018, a blended rate of 24.5% was utilized, calculated as 35% for the first quarter of the fiscal year and 21% for the remaining three quarters. For fiscal 2017, the statutory rate of 35% was utilized.
(2)
The state income tax expense shown above includes the impact of state enhanced oil recovery tax credits and adjustments to the estimated state effective tax rates utilized in the calculation of deferred income taxes.
(3)
Represents amortization of excess deferred federal income taxes under the 2017 Tax Reform Act.
(4)
The $5.0 million benefit in fiscal 2019 represents the reversal of the estimated sequestration of AMT credit refunds. The amount for fiscal 2018 represents the remeasurement of deferred income taxes as a result of the lower U.S. corporate income tax rate, including a $5.0 million estimate for the potential sequestration of AMT credit refunds and the benefit of $9.1 million as a result of the blended tax rate.

Significant components of the Company’s deferred tax liabilities and assets were as follows:
 
At September 30
 
2019
 
2018
 
(Thousands)
Deferred Tax Liabilities:
 
 
 
Property, Plant and Equipment
$
861,278

 
$
770,794

Pension and Other Post-Retirement Benefit Costs
55,795

 
39,541

Other
54,486

 
49,734

Total Deferred Tax Liabilities
971,559

 
860,069

Deferred Tax Assets:
 
 
 
Tax Loss and Credit Carryforwards
(175,542
)
 
(214,128
)
Pension and Other Post-Retirement Benefit Costs
(87,280
)
 
(62,969
)
Other
(55,355
)
 
(75,286
)
Total Gross Deferred Tax Assets
(318,177
)
 
(352,383
)
Valuation Allowance

 
5,000

Total Deferred Tax Assets
(318,177
)
 
(347,383
)
Total Net Deferred Income Taxes
$
653,382

 
$
512,686


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. The Company recognized $31.9 million, that arose directly from excess tax benefits related to stock-based compensation in prior periods, 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 $366.5 million and $370.6 million at September 30, 2019 and 2018, 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 $115.2 million and $115.5 million at September 30, 2019 and 2018, respectively.
The following is a reconciliation of the change in unrecognized tax benefits:
 
Year Ended September 30
 
2019
 
2018
 
2017
 
(Thousands)
Balance at Beginning of Year
$

 
$
1,251

 
$
396

Additions for Tax Positions of Prior Years

 

 
1,251

Reductions for Tax Positions of Prior Years

 
(788
)
 
(396
)
Reductions Related to Settlements with Taxing Authorities

 
(463
)
 

Balance at End of Year
$

 
$

 
$
1,251


The IRS is currently conducting an examination of the Company for fiscal 2019 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 2016 and later years. 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.
During fiscal 2009, preliminary 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, subject to final guidance. The Company is awaiting the issuance of IRS guidance addressing the issue for natural gas utilities.
As of September 30, 2019, the Company has the following carryforwards available:
Jurisdiction
 
Tax Attribute
 
Amount
(Thousands)
 
Expires
Federal Pre-Fiscal 2018
 
Net Operating Loss
 
$
143,571

 
2032-2033
Federal Post-Fiscal 2017
 
Net Operating Loss
 
54,789

 
Unlimited
Pennsylvania
 
Net Operating Loss
 
383,056

 
2030-2039
California
 
Net Operating Loss
 
207,995

 
2030-2039
Federal
 
Alternative Minimum Tax Credit
 
42,546

 
Unlimited
California
 
Alternative Minimum Tax Credit
 
7,711

 
Unlimited
Federal
 
Enhanced Oil Recovery Credit
 
26,790

 
2029-2039
California
 
Enhanced Oil Recovery Credit
 
8,504

 
2037-2039
Federal
 
R&D Tax Credit
 
6,339

 
2031-2039
Federal
 
Charitable Contributions
 
2,097

 
2023

v3.19.3
Capitalization And Short-Term Borrowings
12 Months Ended
Sep. 30, 2019
Capitalization And Short-Term Borrowings [Abstract]  
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, 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(1)
 
 
 
 
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

 
(30,123
)
Net Income Available for Common Stock
 
 
 
 
 
 
391,521

 
 
Dividends Declared on Common Stock ($1.68 Per Share)
 
 
 
 
 
 
(144,290
)
 
 
Other Comprehensive Loss, Net of Tax
 
 
 
 


 
 
 
(37,627
)
Share-Based Payment Expense(1)


 


 
14,235

 
 
 
 
Common Stock Issued Under Stock and Benefit Plans
414

 
414

 
9,342

 


 


Balance at September 30, 2018
85,957

 
85,957

 
820,223

 
1,098,900

 
(67,750
)
Net Income Available for Common Stock
 
 
 
 
 
 
304,290

 
 
Dividends Declared on Common Stock ($1.72 Per Share)
 
 
 
 
 
 
(148,432
)
 
 
Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities
 
 
 
 
 
 
7,437

 
 
Cumulative Effect of Adoption of Authoritative Guidance for Reclassification of Stranded Tax Effects
 
 
 
 
 
 
10,406

 
 
Other Comprehensive Income, Net of Tax
 
 
 
 
 
 
 
 
15,595

Share-Based Payment Expense(1)
 
 
 
 
19,613

 
 
 
 
Common Stock Issued (Repurchased) Under Stock and Benefit Plans
358

 
358

 
(7,572
)
 
 
 
 
Balance at September 30, 2019
86,315

 
$
86,315

 
$
832,264

 
$
1,272,601

(2)
$
(52,155
)
 
(1)
Paid in Capital includes compensation costs associated with SARs, performance shares and/or restricted stock awards. The expense is included within Net Income Available for Common Stock, net of tax benefits.
(2)
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, 2019, $1.1 billion 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 2019, the Company did not issue any original issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan or the Company's 401(k) plans.
During 2019, the Company issued 126,879 original issue shares of common stock as a result of SARs exercises, 80,354 original issue shares of common stock for restricted stock units that vested and 281,882 original issue shares of common stock for performance shares that vested. Holders of stock-based compensation awards will often tender shares of common stock to the Company for payment of applicable withholding taxes. During 2019, 159,413 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 28,771 original issue shares of common stock