NATIONAL FUEL GAS CO, 10-Q filed on 2/1/2019
Quarterly Report
v3.10.0.1
Document And Entity Information - shares
3 Months Ended
Dec. 31, 2018
Jan. 31, 2019
Document And Entity Information [Abstract]    
Document Type 10-Q  
Amendment Flag false  
Document Period End Date Dec. 31, 2018  
Document Fiscal Year Focus 2019  
Document Fiscal Period Focus Q1  
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   86,278,520
Trading Symbol nfg  
Entity Emerging Growth Company false  
Entity Small Business false  
v3.10.0.1
Consolidated Statements Of Income And Earnings Reinvested In The Business (Unaudited) - USD ($)
$ in Thousands
3 Months Ended
Dec. 31, 2018
Dec. 31, 2017
INCOME    
Operating Revenues $ 490,247 $ 419,655
Operating Expenses:    
Property, Franchise and Other Taxes 24,005 20,848
Depreciation, Depletion and Amortization 64,255 55,830
Total Operating Expenses 328,564 270,186
Operating Income 161,683 149,469
Other Income (Expense):    
Other Income (Deductions) (9,602) (3,503)
Interest Expense on Long-Term Debt (25,439) (28,087)
Other Interest Expense (1,073) (502)
Income Before Income Taxes 125,569 117,377
Income Tax Expense (Benefit) 22,909 (81,277)
Net Income Available for Common Stock 102,660 198,654
EARNINGS REINVESTED IN THE BUSINESS    
Balance at Beginning of Period 1,098,900 851,669
Beginning Retained Earnings Unappropriated And Current Period Net Income 1,201,560 1,050,323
Dividends on Common Stock (36,663) (35,590)
Balance at December 31 $ 1,172,334 $ 1,014,733
Earnings Per Common Share, Basic:    
Net Income Available for Common Stock (in dollars per share) $ 1.19 $ 2.32
Earnings Per Common Share, Diluted:    
Net Income Available for Common Stock (in dollars per share) $ 1.18 $ 2.30
Weighted Average Common Shares Outstanding:    
Used in Basic Calculation (shares) 86,032,729 85,630,296
Used in Diluted Calculation (shares) 86,708,814 86,325,537
Dividends Per Common Share:    
Dividends Declared (in dollars per share) $ 0.425 $ 0.415
Purchased Gas [Member]    
Operating Expenses:    
Purchased Gas $ 138,660 $ 94,034
Utility and Energy Marketing [Member]    
INCOME    
Operating Revenues 272,092 225,725
Operating Expenses:    
Operation and Maintenance 43,915 44,080
Exploration and Production and Other [Member]    
INCOME    
Operating Revenues 163,937 140,450
Operating Expenses:    
Operation and Maintenance 32,795 35,083
Pipeline and Storage and Gathering [Member]    
INCOME    
Operating Revenues 54,218 53,480
Operating Expenses:    
Operation and Maintenance 24,934 20,311
Guidance for Recognition and Measurement of Financial Assets and Liabilities [Member]    
EARNINGS REINVESTED IN THE BUSINESS    
Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities $ 7,437 $ 0
v3.10.0.1
Consolidated Statements Of Comprehensive Income (Unaudited) - USD ($)
$ in Thousands
3 Months Ended
Dec. 31, 2018
Dec. 31, 2017
Statement of Comprehensive Income [Abstract]    
Net Income Available for Common Stock $ 102,660 $ 198,654
Other Comprehensive Income (Loss), Before Tax:    
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period 0 (44)
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period 44,518 (5,499)
Reclassification Adjustment for Realized (Gains) Losses on Securities Available for Sale in Net Income 0 (430)
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income 20,517 (12,548)
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
Other Comprehensive Income (Loss), Before Tax 53,297 (18,521)
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period 0 (65)
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period 12,744 (2,305)
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Securities Available for Sale in Net Income 0 (158)
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income 5,794 (5,197)
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
Income Taxes – Net 14,237 (7,725)
Other Comprehensive Income (Loss) 39,060 (10,796)
Comprehensive Income $ 141,720 $ 187,858
v3.10.0.1
Consolidated Balance Sheets (Unaudited) - USD ($)
$ in Thousands
Dec. 31, 2018
Sep. 30, 2018
ASSETS    
Property, Plant and Equipment $ 10,604,089 $ 10,439,839
Less - Accumulated Depreciation, Depletion and Amortization 5,520,472 5,462,696
Property, Plant and Equipment, Net, Total 5,083,617 4,977,143
Current Assets    
Cash and Temporary Cash Investments 109,754 229,606
Hedging Collateral Deposits [1] 2,784 3,441
Receivables – Net of Allowance for Uncollectible Accounts of $26,318 and $24,537, Respectively 192,604 141,498
Unbilled Revenue 74,497 24,182
Gas Stored Underground 30,336 37,813
Materials and Supplies - at average cost 34,947 35,823
Unrecovered Purchased Gas Costs 8,700 4,204
Other Current Assets 69,219 68,024
Total Current Assets 522,841 544,591
Other Assets    
Recoverable Future Taxes 114,219 115,460
Unamortized Debt Expense 15,412 15,975
Other Regulatory Assets 111,611 112,918
Deferred Charges 42,994 40,025
Other Investments 129,715 132,545
Goodwill 5,476 5,476
Prepaid Post-Retirement Benefit Costs 84,609 82,733
Fair Value of Derivative Financial Instruments 34,244 9,518
Other 42,190 102
Total Other Assets 580,470 514,752
Total Assets 6,186,928 6,036,486
Capitalization:    
Common Stock, $1 Par Value Authorized - 200,000,000 Shares; Issued and Outstanding - 86,270,957 Shares and 85,956,814 Shares, Respectively 86,271 85,957
Paid in Capital 817,076 820,223
Earnings Reinvested in the Business 1,172,334 1,098,900
Accumulated Other Comprehensive Loss (28,690) (67,750)
Total Comprehensive Shareholders’ Equity 2,046,991 1,937,330
Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs 2,131,880 2,131,365
Total Capitalization 4,178,871 4,068,695
Current and Accrued Liabilities    
Notes Payable to Banks and Commercial Paper 0 0
Current Portion of Long-Term Debt 0 0
Accounts Payable 127,926 160,031
Amounts Payable to Customers 0 3,394
Dividends Payable 36,663 36,532
Interest Payable on Long-Term Debt 30,016 19,062
Customer Advances 7,351 13,609
Customer Security Deposits 23,842 25,703
Other Accruals and Current Liabilities 191,172 132,693
Fair Value of Derivative Financial Instruments 2,112 49,036
Total Current and Accrued Liabilities 419,082 440,060
Deferred Credits    
Deferred Income Taxes 598,285 512,686
Taxes Refundable to Customers 366,448 370,628
Cost of Removal Regulatory Liability 214,842 212,311
Other Regulatory Liabilities 150,337 146,743
Pension and Other Post-Retirement Liabilities 40,842 66,103
Asset Retirement Obligations 104,343 108,235
Other Deferred Credits 113,878 111,025
Total Deferred Credits 1,588,975 1,527,731
Commitments and Contingencies (Note 7) 0 0
Total Capitalization and Liabilities $ 6,186,928 $ 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.
v3.10.0.1
Consolidated Balance Sheets (Parenthetical) - USD ($)
$ in Thousands
Dec. 31, 2018
Sep. 30, 2018
Statement of Financial Position [Abstract]    
Receivables, Allowance for Uncollectible Accounts $ 26,318 $ 24,537
Common Stock, Par Value $ 1 $ 1
Common Stock, Shares Authorized 200,000,000 200,000,000
Common Stock, Shares Issued 86,270,957 85,956,814
Common Stock, Shares Outstanding 86,270,957 85,956,814
v3.10.0.1
Consolidated Statements Of Cash Flows (Unaudited) - USD ($)
$ in Thousands
3 Months Ended
Dec. 31, 2018
Dec. 31, 2017
OPERATING ACTIVITIES    
Net Income Available for Common Stock $ 102,660 $ 198,654
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:    
Depreciation, Depletion and Amortization 64,255 55,830
Deferred Income Taxes 64,175 (94,676)
Stock-Based Compensation 5,311 3,905
Other 2,182 3,678
Change in:    
Receivables and Unbilled Revenue (101,541) (83,357)
Gas Stored Underground and Materials and Supplies 8,353 10,337
Unrecovered Purchased Gas Costs (4,496) (3,164)
Other Current Assets (1,195) 3,591
Accounts Payable 1,502 13,173
Amounts Payable to Customers (3,394) 251
Customer Advances (6,258) 2,697
Customer Security Deposits (1,861) 2,131
Other Accruals and Current Liabilities 38,412 11,532
Other Assets (42,400) (5,275)
Other Liabilities (21,333) (21,775)
Net Cash Provided by Operating Activities 104,372 97,532
INVESTING ACTIVITIES    
Capital Expenditures (177,567) (142,613)
Other (2,549) 2,612
Net Cash Used in Investing Activities (180,116) (140,001)
Financing Activities    
Reduction of Long-Term Debt 0 (307,047)
Dividends Paid on Common Stock (36,532) (35,500)
Net Repurchases of Common Stock (8,233) (1,501)
Net Cash Used in Financing Activities (44,765) (344,048)
Net Decrease in Cash, Cash Equivalents, and Restricted Cash (120,509) (386,517)
Cash, Cash Equivalents and Restricted Cash at October 1 233,047 557,271
Cash, Cash Equivalents and Restricted Cash at December 31 112,538 170,754
Supplemental Disclosure of Cash Flow Information, Non-Cash Investing Activities:    
Non-Cash Capital Expenditures 86,175 56,116
Receivable from Sale of Oil and Gas Producing Properties $ 0 $ 17,310
v3.10.0.1
Summary Of Significant Accounting Policies
3 Months Ended
Dec. 31, 2018
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. Operating Income increased $7.5 million and Other Income (Deductions) decreased by the same amount for the quarter ended December 31, 2017 as a result of the reclassifications. For the quarter ended December 31, 2018, Other Income (Deductions) includes $7.4 million of pension and postretirement benefit costs.

Earnings for Interim Periods.  The Company, in its opinion, has included all adjustments (which consist of only normally recurring adjustments, unless otherwise disclosed in this Form 10-Q) that are necessary for a fair statement of the results of operations for the reported periods. The consolidated financial statements and notes thereto, included herein, should be read in conjunction with the financial statements and notes for the years ended September 30, 2018, 2017 and 2016 that are included in the Company's 2018 Form 10-K.  The consolidated financial statements for the year ended September 30, 2019 will be audited by the Company's independent registered public accounting firm after the end of the fiscal year.
 
The earnings for the three months ended December 31, 2018 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2019.  Most of the business of the Utility and Energy Marketing segments is seasonal in nature and is influenced by weather conditions.  Due to the seasonal nature of the heating business in the Utility and Energy Marketing segments, earnings during the winter months normally represent a substantial part of the earnings that those segments are expected to achieve for the entire fiscal year.  The Company’s business segments are discussed more fully in Note 8 – Business Segment Information.
 
Consolidated Statements 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):
 
Three Months Ended
December 31, 2018
 
Three Months Ended
December 31, 2017
 
Balance at October 1, 2018
 
Balance at December 31, 2018
 
Balance at October 1, 2017
 
Balance at December 31, 2017
 
 
 
 
 
 
 
 
Cash and Temporary Cash Investments
$
229,606

 
$
109,754

 
$
555,530

 
$
166,289

Hedging Collateral Deposits
3,441

 
2,784

 
1,741

 
4,465

Cash, Cash Equivalents, and Restricted Cash
$
233,047

 
$
112,538

 
$
557,271

 
$
170,754



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 comprised 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.

Gas Stored Underground.  In the Utility segment, gas stored underground is carried at lower of cost or net realizable value, on a LIFO method.  Gas stored underground normally declines during the first and second quarters of the year and is replenished during the third and fourth quarters.  In the Utility segment, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption “Other Accruals and Current Liabilities.”  Such reserve, which amounted to $2.0 million at December 31, 2018, is reduced to zero by September 30 of each year as the inventory is replenished.
 
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.
 
Capitalized costs include costs related to unproved properties, which are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired.  Such costs amounted to $58.5 million and $62.2 million at December 31, 2018 and September 30, 2018, respectively.  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.
 
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 December 31, 2018, the ceiling exceeded the book value of the oil and gas properties by approximately $776.3 million. In adjusting estimated future cash flows for hedging under the ceiling test at December 31, 2018, estimated future net cash flows were decreased by $44.4 million.
    
Accumulated Other Comprehensive Loss.  The components of Accumulated Other Comprehensive Loss and changes for the three months ended December 31, 2018 and 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
Three Months Ended December 31, 2018
 
 
 
 
 
 
 
Balance at October 1, 2018
$
(28,611
)
 
$
7,437

 
$
(46,576
)
 
$
(67,750
)
Other Comprehensive Gains and Losses Before Reclassifications
31,774

 

 

 
31,774

Amounts Reclassified From Other Comprehensive Income (Loss)
14,723

 
(7,437
)
 

 
7,286

Balance at December 31, 2018
$
17,886

 
$

 
$
(46,576
)
 
$
(28,690
)
Three Months Ended December 31, 2017
 
 
 
 
 
 
 
Balance at October 1, 2017
$
20,801

 
$
7,562

 
$
(58,486
)
 
$
(30,123
)
Other Comprehensive Gains and Losses Before Reclassifications
(3,194
)
 
21

 

 
(3,173
)
Amounts Reclassified From Other Comprehensive Income (Loss)
(7,351
)
 
(272
)
 

 
(7,623
)
Balance at December 31, 2017
$
10,256

 
$
7,311

 
$
(58,486
)
 
$
(40,919
)

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 for 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 Loss.  The details about the reclassification adjustments out of accumulated other comprehensive loss for the three months ended December 31, 2018 and 2017 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands):
Details About Accumulated Other Comprehensive Loss Components
 
Amount of Gain or (Loss) Reclassified from
Accumulated Other Comprehensive Loss
 
Affected Line Item in the Statement Where Net Income is Presented
 
Three Months Ended December 31,
 
 
2018
 
2017
 
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
 
 
 
 
 
 
     Commodity Contracts
 

($18,522
)
 

$12,842

 
Operating Revenues
     Commodity Contracts
 
(902
)
 
196

 
Purchased Gas
     Foreign Currency Contracts
 
(1,093
)
 
(490
)
 
Operating Revenues
Gains (Losses) on Securities Available for Sale
 
11,738

 

 
Earnings Reinvested in the Business
Gains (Losses) on Securities Available for Sale
 

 
430

 
Other Income (Deductions)
 
 
(8,779
)
 
12,978

 
Total Before Income Tax
 
 
1,493

 
(5,355
)
 
Income Tax Expense
 
 

($7,286
)
 

$7,623

 
Net of Tax

Other Current Assets.  The components of the Company’s Other Current Assets are as follows (in thousands):
                            
At December 31, 2018
 
At September 30, 2018
 
 
 
 
Prepayments
$
8,765

 
$
11,126

Prepaid Property and Other Taxes
15,602

 
14,088

Federal Income Taxes Receivable
22,474

 
22,457

State Income Taxes Receivable
9,030

 
8,822

Fair Values of Firm Commitments
986

 
1,739

Regulatory Assets
12,362

 
9,792

 
$
69,219

 
$
68,024



Other Assets.  The components of the Company’s Other Assets are as follows (in thousands):
                            
At December 31, 2018
 
At September 30, 2018
 
 
 
 
Federal Income Taxes Receivable
$
42,093

 
$

Other
97

 
102

 
$
42,190

 
$
102


 
Other Accruals and Current Liabilities.  The components of the Company’s Other Accruals and Current Liabilities are as follows (in thousands):
                            
At December 31, 2018
 
At September 30, 2018
 
 
 
 
Accrued Capital Expenditures
$
69,321

 
$
38,354

Regulatory Liabilities
45,343

 
57,425

Reserve for Gas Replacement
2,025

 

Liability for Royalty and Working Interests
26,801

 
12,062

Other
47,682

 
24,852

 
$
191,172

 
$
132,693


 
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.  For the quarter ended December 31, 2018, 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 318,106 securities and 157,603 securities excluded as being antidilutive for the quarters ended December 31, 2018 and December 31, 2017, respectively.
 
Stock-Based Compensation.  The Company granted 244,734 performance shares during the quarter ended December 31, 2018. The weighted average fair value of such performance shares was $55.67 per share for the quarter ended December 31, 2018. 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.
 
Half of the performance shares granted during the quarter ended December 31, 2018 must meet a performance goal related to relative return on capital over a three-year performance cycle.  The performance goal over the performance cycle 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 quarter ended December 31, 2018 must meet a performance goal related to relative total shareholder return over a three-year performance cycle.  The performance goal over the performance cycle 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 total 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 total shareholder return performance shares ("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.
 
The Company granted 111,108 non-performance based restricted stock units during the quarter ended December 31, 2018.  The weighted average fair value of such non-performance based restricted stock units was $49.72 per share for the quarter ended December 31, 2018.  Restricted stock units 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. These non-performance based restricted stock units do not entitle the participant to receive dividends during the vesting period. The accounting for 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 must be reduced by the present value of forgone dividends over the vesting term of the award.
 
New Authoritative Accounting and Financial Reporting Guidance.     In February 2016, the FASB issued authoritative guidance, which has subsequently been amended, 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. The Company is currently reviewing all existing leases and other agreements that may be considered leases under the new authoritative guidance and evaluating the effect the revised guidance will have on its financial statements, internal controls, and related disclosures. The Company will continue to monitor relevant industry and regulatory guidance and adjust its implementation approach as necessary.

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 new guidance will be effective as of the Company’s first quarter of fiscal 2020, with early adoption permitted. The Company does not expect adoption of this guidance to have a significant impact on its consolidated financial statements and is currently evaluating the impact of this guidance.

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 new guidance will be effective as of the Company’s first quarter of fiscal 2020, with early adoption permitted. The Company will be filing with the FERC for regulatory approval of the reclassification to retained earnings for the Company’s Pipeline and Storage segment.
v3.10.0.1
Revenue from Contracts with Customers
3 Months Ended
Dec. 31, 2018
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 the Energy Marketing segment. 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 quarter ended December 31, 2018, presented by type of service from each reportable segment.
Quarter Ended December 31, 2018 (Thousands)
 
 
 
 

 
 

 
 

 
 

Revenues By Type of Service
Exploration and Production
 
Pipeline and Storage
 
Gathering
 
Utility
 
Energy Marketing
 
All Other
 
Corporate and Intersegment Eliminations
 
Total Consolidated
Production of Natural Gas
$
135,911

 
$

 
$

 
$

 
$

 
$

 
$

 
$
135,911

Production of Crude Oil
37,555

 

 

 

 

 

 

 
37,555

Natural Gas Processing
975

 

 

 

 

 

 

 
975

Natural Gas Gathering Services

 

 
29,690

 

 

 

 
(29,690
)
 

Natural Gas Transportation Service

 
56,135

 

 
35,631

 

 

 
(17,065
)
 
74,701

Natural Gas Storage Service

 
18,929

 

 

 

 

 
(7,973
)
 
10,956

Natural Gas Residential Sales

 

 

 
166,867

 

 

 

 
166,867

Natural Gas Commercial Sales

 

 

 
22,047

 

 

 

 
22,047

Natural Gas Industrial Sales

 

 

 
1,501

 

 

 

 
1,501

Natural Gas Marketing

 

 

 

 
49,287

 

 
(332
)
 
48,955

Other
382

 
2,005

 

 
(2,861
)
 

 
1,007

 
(404
)
 
129

Total Revenues from Contracts with Customers
174,823

 
77,069

 
29,690

 
223,185

 
49,287

 
1,007

 
(55,464
)
 
499,597

Alternative Revenue Programs

 

 

 
(528
)
 

 

 

 
(528
)
Derivative Financial Instruments
(11,947
)
 

 

 

 
3,125

 

 

 
(8,822
)
Total Revenues
$
162,876

 
$
77,069

 
$
29,690

 
$
222,657

 
$
52,412

 
$
1,007

 
$
(55,464
)
 
$
490,247



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: $123.5 million for the remainder of fiscal 2019; $149.4 million for fiscal 2020; $128.5 million for fiscal 2021; $113.6 million for fiscal 2022; $82.7 million for fiscal 2023; and $370.7 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 Segment Revenue

The Company’s Energy Marketing segment records revenue for competitively priced natural gas sales in western and central New York and northwestern Pennsylvania. Sales are provided largely to industrial, wholesale, commercial, public authority and residential customers. The Energy Marketing 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 Energy Marketing segment. The Energy Marketing 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 contracted or market based rate, indicates the value to the customer, and is used for revenue recognition purposes by the Energy Marketing segment as specified by the “invoice practical expedient” (the amount that the Energy Marketing segment has the right to invoice) under the authoritative guidance for revenue recognition. Since the Energy Marketing segment 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. The Energy Marketing segment 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 the Energy Marketing segment 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.
v3.10.0.1
Fair Value Measurements
3 Months Ended
Dec. 31, 2018
Fair Value Disclosures [Abstract]  
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 December 31, 2018 and September 30, 2018.  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.  
Recurring Fair Value Measures
At fair value as of December 31, 2018
(Thousands of Dollars)   
Level 1
 
Level 2
 
Level 3
 
Netting Adjustments(1)
 
Total(1)
Assets:
 

 
 

 
 

 
 

 
 

Cash Equivalents – Money Market Mutual Funds
$
86,168

 
$

 
$

 
$

 
$
86,168

Derivative Financial Instruments:
 

 
 

 
 

 
 

 
 

Commodity Futures Contracts – Gas
1,077

 

 

 
(1,077
)
 

Over the Counter Swaps – Gas and Oil

 
43,274

 

 
(5,393
)
 
37,881

Foreign Currency Contracts

 

 

 
(3,637
)
 
(3,637
)
Other Investments:
 

 
 

 
 

 
 

 
 

Balanced Equity Mutual Fund
35,498

 

 

 

 
35,498

Fixed Income Mutual Fund
53,367

 

 

 

 
53,367

Common Stock – Financial Services Industry
1,437

 

 

 

 
1,437

Hedging Collateral Deposits
2,784

 

 

 

 
2,784

Total                                           
$
180,331

 
$
43,274

 
$

 
$
(10,107
)
 
$
213,498

 
 
 
 
 
 
 
 
 
 
Liabilities:
 

 
 

 
 

 
 

 
 

Derivative Financial Instruments:
 

 
 

 
 

 
 

 
 

Commodity Futures Contracts – Gas
$
2,291

 
$

 
$

 
$
(1,077
)
 
$
1,214

Over the Counter Swaps – Gas and Oil

 
6,249

 

 
(5,393
)
 
856

Foreign Currency Contracts

 
3,679

 

 
(3,637
)
 
42

Total
$
2,291

 
$
9,928

 
$

 
$
(10,107
)
 
$
2,112

Total Net Assets/(Liabilities)
$
178,040

 
$
33,346

 
$

 
$

 
$
211,386

 
Recurring Fair Value Measures
At fair value as of September 30, 2018
(Thousands of Dollars)   
Level 1
 
Level 2
 
Level 3
 
Netting Adjustments(1)
 
Total(1)
Assets:
 

 
 

 
 

 
 

 
 

Cash Equivalents – Money Market Mutual Funds
$
215,272

 
$

 
$

 
$

 
$
215,272

Derivative Financial Instruments:
 

 
 

 
 

 
 

 
 

Commodity Futures Contracts – Gas
1,075

 

 

 
(1,075
)
 

Over the Counter Swaps – Gas and Oil

 
26,074

 

 
(17,041
)
 
9,033

Foreign Currency Contracts

 
443

 

 
(443
)
 

Other Investments:
 

 
 

 
 

 
 

 
 

Balanced Equity Mutual Fund
38,468

 

 

 

 
38,468

Fixed Income Mutual Fund
51,331

 

 

 

 
51,331

Common Stock – Financial Services Industry
2,776

 

 

 

 
2,776

Hedging Collateral Deposits
3,441

 

 

 

 
3,441

Total                                           
$
312,363

 
$
26,517

 
$

 
$
(18,559
)
 
$
320,321

 
 
 
 
 
 
 
 
 
 
Liabilities:
 

 
 

 
 

 
 

 
 

Derivative Financial Instruments:
 

 
 

 
 

 
 

 
 

Commodity Futures Contracts – Gas
$
2,412

 
$

 
$

 
$
(1,075
)
 
$
1,337

Over the Counter Swaps – Gas and Oil

 
64,224

 

 
(17,041
)
 
47,183

     Foreign Currency Contracts

 
959

 

 
(443
)
 
516

Total
$
2,412

 
$
65,183

 
$

 
$
(18,559
)
 
$
49,036

Total Net Assets/(Liabilities)
$
309,951

 
$
(38,666
)
 
$

 
$

 
$
271,285


(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 December 31, 2018 and September 30, 2018, 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 were $2.8 million at December 31, 2018 and $3.4 million at September 30, 2018, which were associated with these futures contracts and have been reported in Level 1 as well. The derivative financial instruments reported in Level 2 at December 31, 2018 and September 30, 2018 consist of natural gas price swap agreements used in the Company’s Exploration and Production and Energy Marketing segments, 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 derivative financial instruments reported in Level 2 at December 31, 2018 also include basis hedge swap agreements used in the Company's Energy Marketing 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 December 31, 2018, 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 quarters ended December 31, 2018 and December 31, 2017, there were no assets or liabilities measured at fair value and classified as Level 3. For the quarters ended December 31, 2018 and December 31, 2017, no transfers in or out of Level 1 or Level 2 occurred.
v3.10.0.1
Financial Instruments
3 Months Ended
Dec. 31, 2018
Financial Instruments, Owned, at Fair Value [Abstract]  
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 (in thousands): 
 
December 31, 2018
 
September 30, 2018
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
Long-Term Debt
$
2,131,880

 
$
2,114,990

 
$
2,131,365

 
$
2,121,861


 
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. The components of the Company's Other Investments are as follows (in thousands):
 
At December 31, 2018
 
At September 30, 2018
 
 
 
 
Life Insurance Contracts
$
39,413

 
$
39,970

Equity Mutual Fund
35,498

 
38,468

Fixed Income Mutual Fund
53,367

 
51,331

Marketable Equity Securities
1,437

 
2,776

 
$
129,715

 
$
132,545


 
Investments in life insurance contracts are stated at their cash surrender values or net present value. Investments in an equity mutual fund, a fixed income mutual fund and the stock of an insurance company (marketable equity securities) are stated at fair value based on quoted market prices with changes in fair value recognized in net income. 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 duration of the Company’s combined cash flow and fair value commodity hedges does not typically exceed 5 years while the foreign currency forward contracts do not exceed 7 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 December 31, 2018 and September 30, 2018.  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 December 31, 2018, the Company had the following commodity derivative contracts (swaps and futures contracts) outstanding:
Commodity
Units

 
Natural Gas
97.3

 Bcf (short positions)
Natural Gas
2.4

 Bcf (long positions)
Crude Oil
3,735,000

 Bbls (short positions)
    
As of December 31, 2018, the Company was hedging a total of $89.5 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts (long positions).
As of December 31, 2018, the Company had $27.6 million ($17.9 million after tax) of net hedging gains included in the accumulated other comprehensive income (loss) balance. It is expected that $15.2 million ($9.9 million after tax) of 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
Three Months Ended December 31, 2018 and 2017 (Thousands of Dollars)
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 Three Months Ended December 31,
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 Three Months Ended December 31,
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 Three Months Ended December 31,
 
2018
2017
 
2018
2017
 
2018
2017
Commodity Contracts
$
50,052

$
(5,948
)
Operating Revenue
$
(18,522
)
$
12,842

Operating Revenue
$
6,505

$
(433
)
Commodity Contracts
(1,279
)
956

Purchased Gas
(902
)
196

Not Applicable


Foreign Currency Contracts
(4,255
)
(507
)
Operating Revenue
(1,093
)
(490
)
Not Applicable


Total
$
44,518

$
(5,499
)
 
$
(20,517
)
$
12,548

 
$
6,505

$
(433
)
 
 
 
 
 
 
 
 
 

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 December 31, 2018, the Company’s Energy Marketing segment had fair value hedges covering approximately 25.6 Bcf (25.4 Bcf of fixed price sales commitments and 0.2 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
Three Months Ended December 31, 2018
(In Thousands)
Amount of Gain or (Loss) on the Hedged Item Recognized in the Consolidated Statement of Income for the
Three Months Ended December 31, 2018
(In Thousands)
Commodity Contracts
Operating Revenues
$
(78
)
$
78

Commodity Contracts
Purchased Gas
$
142

$
(142
)
 
 
$
64

$
(64
)
 
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 eighteen counterparties of which fourteen are in a net gain position. On average, the Company had $2.4 million of credit exposure per counterparty in a gain position at December 31, 2018. The maximum credit exposure per counterparty in a gain position at December 31, 2018 was $6.6 million. As of December 31, 2018, 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 December 31, 2018, fifteen of the eighteen 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 December 31, 2018, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $21.1 million according to the Company’s internal model (discussed in Note 3 — Fair Value Measurements).  At December 31, 2018, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $0.9 million according to the Company's internal model. 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 December 31, 2018.    
 
For its exchange traded futures contracts, the Company was required to post $2.8 million in hedging collateral deposits as of December 31, 2018. 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.
v3.10.0.1
Income Taxes
3 Months Ended
Dec. 31, 2018
Income Tax Disclosure [Abstract]  
Income Taxes
Income Taxes

The effective tax rate for the quarters ended December 31, 2018 and December 31, 2017 was 18.2% and negative 69.2%, respectively. The difference primarily relates to the impact of the one-time remeasurement of accumulated deferred income taxes under the 2017 Tax Reform Act during fiscal 2018 discussed below.
On December 22, 2017, the 2017 Tax Reform Act was enacted. The 2017 Tax Reform Act significantly changed the taxation of business entities and included 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. In addition, beginning in fiscal 2019, the corporate alternative minimum tax (AMT) is eliminated and there are enhanced limitations on the deductibility of certain executive compensation. For the rate regulated subsidiaries, the 2017 Tax Reform Act also allows for the continued deductibility of interest expense, the elimination of full expensing for tax purposes of certain property acquired after September 30, 2018 and the continuation of certain rate normalization requirements for accelerated depreciation benefits. The non-rate regulated subsidiaries are allowed full expensing of certain property acquired after September 27, 2017 and have potential limitations on the deductibility of interest expense beginning in fiscal 2019.
The changes noted above had a material impact on the financial statements in the year ended September 30, 2018. The Company’s accumulated 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. For further discussion, refer to Note 10 - Regulatory Matters.
The 2017 Tax Reform Act also provides that the Company’s existing AMT credit carryovers are refundable, if not utilized to reduce tax, beginning in fiscal 2019. 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. In addition, the Company reclassified the estimated fiscal 2019 refund, approximately $42.1 million, from Deferred Income Taxes to Other Assets.
The SEC issued guidance in Staff Accounting Bulletin 118 (SAB 118) which provided 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 accumulated deferred income taxes. Any subsequent guidance or clarification related to the 2017 Tax Reform Act will be accounted for in the period issued.
v3.10.0.1
Capitalization
3 Months Ended
Dec. 31, 2018
Capitalization, Long-term Debt and Equity [Abstract]  
Capitalization
Capitalization

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 October 1, 2017
85,543

 
$
85,543

 
$
796,646

 
$
851,669

 
$
(30,123
)
Net Income Available for Common Stock
 
 
 
 
 
 
198,654

 
 
Dividends Declared on Common Stock ($0.415 Per Share)
 
 
 
 
 
 
(35,590
)
 
 
Other Comprehensive Loss, Net of Tax
 
 
 
 
 
 
 
 
(10,796
)
Share-Based Payment Expense (1)
 
 
 
 
3,511

 
 
 
 
Common Stock Issued Under Stock and Benefit Plans
218

 
218

 
191

 
 
 
 
Balance at December 31, 2017
85,761

 
85,761

 
800,348

 
1,014,733

 
(40,919
)
 
 
 
 
 
 
 
 
 
 
Balance at October 1, 2018
85,957

 
$
85,957

 
$
820,223

 
$
1,098,900

 
$
(67,750
)
Net Income Available for Common Stock
 
 
 
 
 
 
102,660

 
 
Dividends Declared on Common Stock ($0.425 Per Share)
 
 
 
 
 
 
(36,663
)
 
 
Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities
 
 
 
 
 
 
7,437

 
 
Other Comprehensive Income, Net of Tax
 
 
 
 
 
 
 
 
39,060

Share-Based Payment Expense (1)
 
 
 
 
4,917

 
 
 
 
Common Stock Issued (Repurchased) Under Stock and Benefit Plans
314

 
314

 
(8,064
)
 
 
 
 
Balance at December 31, 2018
86,271

 
$
86,271

 
$
817,076

 
$
1,172,334

 
$
(28,690
)


(1) 
Paid in Capital includes compensation costs associated with performance shares and/or restricted stock awards. The expense is included within Net Income Available For Common Stock, net of tax benefits.
 
Common Stock.  During the three months ended December 31, 2018, the Company issued 94,047 original issue shares of common stock as a result of SARs exercises, 79,654 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.  The Company also issued 7,020 original issue shares of 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 three months ended December 31, 2018.  Holders of stock-based compensation awards will often tender shares of common stock to the Company for payment of applicable withholding taxes.  During the three months ended December 31, 2018, 148,460 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.
 
Current Portion of Long-Term Debt.  None of the Company's long-term debt as of December 31, 2018 and September 30, 2018 had a maturity date within the following twelve-month period.
v3.10.0.1
Commitments And Contingencies
3 Months Ended
Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]  
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 December 31, 2018, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $7.5 million, which includes a $4.1 million estimated minimum liability to remediate a former manufactured gas plant site located in New York.  In March 2018, the NYDEC issued a Record of Decision for this New York site and the minimum liability reflects the remedy selected in the Record of Decision. The Company's liability for such clean-up costs has been recorded in Other Deferred Credits on the Consolidated Balance Sheet at December 31, 2018. The Company expects to recover its environmental clean-up costs through rate recovery over a period of approximately 4 years and 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 have an adverse financial impact on the Company.
    
Northern Access Project. On February 3, 2017, Supply Corporation and Empire received FERC approval of the Northern Access 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. On August 6, 2018, the FERC issued an Order finding that the NYDEC exceeded the statutory time frame to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification. Rehearing requests have been filed at FERC. In light of these pending legal actions and the need to complete necessary project development activities in advance of construction, the target in-service date for the project is expected to be no earlier than fiscal 2022. As a result of the decision of the NYDEC, Supply Corporation and Empire evaluated the capitalized project costs for impairment as of December 31, 2018 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 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 $76.5 million at December 31, 2018. The project costs are included within Property, Plant and Equipment and Deferred Charges on the Consolidated Balance Sheet.
 
Other.  The Company is involved in other litigation and regulatory matters arising in the normal course of business.  These other 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.
v3.10.0.1
Business Segment Information
3 Months Ended
Dec. 31, 2018
Segment Reporting [Abstract]  
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 data presented in the tables below reflect financial information for the segments and reconciliations to consolidated amounts.  As stated in the 2018 Form 10-K, 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.  There have not been any changes in the basis of segmentation nor in the basis of measuring segment profit or loss from those used in the Company’s 2018 Form 10-K.  A listing of segment assets at December 31, 2018 and September 30, 2018 is shown in the tables below.  
Quarter Ended December 31, 2018 (Thousands)
 
 
 
 
 
 
 
Exploration and Production
Pipeline and Storage
Gathering
Utility
Energy Marketing
Total Reportable Segments
All Other
Corporate and Intersegment Eliminations
Total Consolidated
Revenue from External Customers
$162,876
$54,218
$—
$220,012
$52,080
$489,186
$1,007
$54
$490,247
Intersegment Revenues
$—
$22,851
$29,690
$2,645
$332
$55,518
$—
$(55,518)
$—
Segment Profit: Net Income (Loss)
$38,214
$25,102
$14,183
$25,649
$(302)