[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended December 31, 2018
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from____ to_____
Commission File Number 1-3880
NATIONAL FUEL GAS COMPANY
(Exact name of registrant as specified in its charter)
New Jersey
13-1086010
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
6363 Main Street
Williamsville, New York
14221
(Address of principal executive offices)
(Zip Code)
(716) 857-7000
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. YES þ NO ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). YES þ NO ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer
þ
Accelerated Filer
¨
Non-Accelerated Filer
¨
Smaller Reporting Company
¨
Emerging Growth Company
¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES ¨ NO þ
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: Common stock, par value $1.00 per share, outstanding at January 31, 2019: 86,278,520 shares.
The total heat value (Btu) of natural gas and oil expressed as a volume of natural gas. The Company uses a conversion formula of 1 barrel of oil = 6 Mcf of natural gas.
Btu
British thermal unit; the amount of heat needed to raise the temperature of one pound of water one degree Fahrenheit
Capital expenditure
Represents additions to property, plant, and equipment, or the amount of money a company spends to buy capital assets or upgrade its existing capital assets.
Cashout revenues
A cash resolution of a gas imbalance whereby a customer (e.g. a marketer) pays for gas the customer receives in excess of amounts delivered into pipeline/storage or distribution systems by the customer’s shipper.
Degree day
A measure of the coldness of the weather experienced, based on the extent to which the daily average temperature falls below a reference temperature, usually 65 degrees Fahrenheit.
Derivative
A financial instrument or other contract, the terms of which include an underlying variable (a price, interest rate, index rate, exchange rate, or other variable) and a notional amount (number of units, barrels, cubic feet, etc.). The terms also permit for the instrument or contract to be settled net and no initial net investment is required to enter into the financial instrument or contract. Examples include futures contracts, forward contracts, options, no cost collars and swaps.
Costs incurred to obtain access to proved oil and gas reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas
Dodd-Frank Act
Dodd-Frank Wall Street Reform and Consumer Protection Act.
Dth
Decatherm; one Dth of natural gas has a heating value of 1,000,000 British thermal units, approximately equal to the heating value of 1 Mcf of natural gas.
Exchange Act
Securities Exchange Act of 1934, as amended
Expenditures for long-lived assets
Includes capital expenditures, stock acquisitions and/or investments in partnerships.
Exploration costs
Costs incurred in identifying areas that may warrant examination, as well as costs incurred in examining specific areas, including drilling exploratory wells.
Exploratory well
A well drilled in unproven or semi-proven territory for the purpose of ascertaining the presence underground of a commercial hydrocarbon deposit.
FERC 7(c) application
An application to the FERC under Section 7(c) of the federal Natural Gas Act for authority to construct, operate (and provide services through) facilities to transport or store natural gas in interstate commerce.
Firm transportation and/or storage
The transportation and/or storage service that a supplier of such service is obligated by contract to provide and for which the customer is obligated to pay whether or not the service is utilized.
GAAP
Accounting principles generally accepted in the United States of America
Goodwill
An intangible asset representing the difference between the fair value of a company and the price at which a company is purchased.
Hedging
A method of minimizing the impact of price, interest rate, and/or foreign currency exchange rate changes, often times through the use of derivative financial instruments.
Hub
Location where pipelines intersect enabling the trading, transportation, storage, exchange, lending and borrowing of natural gas.
ICE
Intercontinental Exchange. An exchange which maintains a futures market for crude oil and natural gas.
Interruptible transportation and/or storage
The transportation and/or storage service that, in accordance with contractual arrangements, can be interrupted by the supplier of such service, and for which the customer does not pay unless utilized.
LDC
Local distribution company
LIBOR
London Interbank Offered Rate
LIFO
Last-in, first-out
Marcellus Shale
A Middle Devonian-age geological shale formation that is present nearly a mile or more below the surface in the Appalachian region of the United States, including much of Pennsylvania and southern New York.
Mbbl
Thousand barrels (of oil)
Mcf
Thousand cubic feet (of natural gas)
MD&A
Management’s Discussion and Analysis of Financial Condition and Results of Operations
MDth
Thousand decatherms (of natural gas)
MMBtu
Million British thermal units (heating value of one decatherm of natural gas)
MMcf
Million cubic feet (of natural gas)
NEPA
National Environmental Policy Act of 1969, as amended
NGA
The Natural Gas Act of 1938, as amended; the federal law regulating interstate natural gas pipeline and storage companies, among other things, codified beginning at 15 U.S.C. Section 717.
NYMEX
New York Mercantile Exchange. An exchange which maintains a futures market for crude oil and natural gas.
A bidding procedure used by pipelines to allocate firm transportation or storage capacity among prospective shippers, in which all bids submitted during a defined time period are evaluated as if they had been submitted simultaneously.
Precedent Agreement
An agreement between a pipeline company and a potential customer to sign a service agreement after specified events (called “conditions precedent”) happen, usually within a specified time.
Proved developed reserves
Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved undeveloped (PUD) reserves
Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required to make these reserves productive.
Reserves
The unproduced but recoverable oil and/or gas in place in a formation which has been proven by production.
Revenue decoupling mechanism
A rate mechanism which adjusts customer rates to render a utility financially indifferent to throughput decreases resulting from conservation.
S&P
Standard & Poor’s Rating Service
SAR
Stock appreciation right
Service agreement
The binding agreement by which the pipeline company agrees to provide service and the shipper agrees to pay for the service.
Stock acquisitions
Investments in corporations
Utica Shale
A Middle Ordovician-age geological formation lying several thousand feet below the Marcellus Shale in the Appalachian region of the United States, including much of Ohio, Pennsylvania, West Virginia and southern New York.
VEBA
Voluntary Employees’ Beneficiary Association
WNC
Weather normalization clause; a clause in utility rates which adjusts customer rates to allow a utility to recover its normal operating costs calculated at normal temperatures. If temperatures during the measured period are warmer than normal, customer rates are adjusted upward in order to recover projected operating costs. If temperatures during the measured period are colder than normal, customer rates are adjusted downward so that only the projected operating costs will be recovered.
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period
—
(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
—
(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
)
—
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
—
(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
—
(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
)
—
Income Taxes – Net
14,237
(7,725
)
Other Comprehensive Income (Loss)
39,060
(10,796
)
Comprehensive Income
$
141,720
$
187,858
See Notes to Condensed Consolidated Financial Statements
Notes to Condensed Consolidated Financial Statements
(Unaudited)
Note 1 - 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:
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.
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.
Note 3 – 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.
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.
Note 4 – 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.
Note 5 - 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.
Note 6 - 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.
Note 7 - 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.
Note 8 – 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.
Note 9 – Retirement Plan and Other Post-Retirement Benefits
Components of Net Periodic Benefit Cost (in thousands):
Retirement Plan
Other Post-Retirement Benefits
Three Months Ended December 31,
2018
2017
2018
2017
Service Cost
$
2,120
$
2,480
$
380
$
458
Interest Cost
9,594
8,252
4,286
3,700
Expected Return on Plan Assets
(15,591
)
(15,429
)
(7,539
)
(7,871
)
Amortization of Prior Service Cost (Credit)
206
235
(107
)
(107
)
Amortization of Losses
8,024
9,301
1,490
2,639
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)
819
1,721
3,971
3,608
Net Periodic Benefit Cost
$
5,172
$
6,560
$
2,481
$
2,427
(1)
The Company’s policy is to record retirement plan and other post-retirement benefit costs in the Utility segment on a volumetric basis to reflect the fact that the Utility segment experiences higher throughput of natural gas in the winter months and lower throughput of natural gas in the summer months.
Employer Contributions. During the three months ended December 31, 2018, the Company contributed $29.2 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and $0.7 million to its VEBA trusts for its other post-retirement benefits. In the remainder of 2019, the Company may contribute up to $5.0 million to the Retirement Plan and the Company expects its contributions to the VEBA trusts to be in the range of $2.0 million to $3.0 million.
Note 10 – Regulatory Matters
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%.
On August 9, 2018, in response to the enactment of the 2017 Tax Reform Act, the NYPSC issued an Order Determining Rate Treatment of Tax Changes directing utilities to make compliance filings effective October 1, 2018 to begin providing sur-credits to customers reflecting tax savings associated with the 2017 Tax Reform Act. In compliance with that order, Distribution Corporation filed the necessary tariff amendments to implement the sur-credit effective October 1, 2018. At December 31, 2018, a refund provision of $8.6 million associated with the impact of the 2017 Tax Reform Act in the New York jurisdiction was included in Other Accruals and Current Liabilities on the Consolidated Balance Sheet. Refer to Note 5 - Income Taxes for further discussion of the 2017 Tax Reform Act.
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.
In response to the issuance of the 2017 Tax Reform Act, the PaPUC issued an Order to Distribution Corporation on May 17, 2018, requiring that Distribution Corporation file a tariff supplement establishing temporary rates to implement refunds of 2.2% on customer rates beginning July 1, 2018. In compliance with the May 17, 2018 PaPUC Order, Distribution Corporation filed a subsequent tariff supplement adjusting the negative surcharge in connection with the start of its new fiscal year, with the new rates effective October 1, 2018. All rates are subject to reconciliation. At December 31, 2018, a refund provision of $4.4 million associated with the impact of the 2017 Tax Reform Act in the Pennsylvania jurisdiction was included in Other Accruals and Current Liabilities on the Consolidated Balance Sheet. Refer to Note 5 - Income Taxes for further discussion of the 2017 Tax Reform Act.
FERC Jurisdiction
Supply Corporation currently has no active rate case on file. Supply Corporation's current rate settlement requires a rate case filing no later than December 31, 2019. In response to the FERC’s July 2018 Final Rule in RM18-11-000, et. al (Order No. 849), on December 6, 2018, Supply Corporation filed its Form 501-G, which addresses the impact of the 2017 Tax Reform Act, and advised the Commission that it would make a Section 4 rate filing no later than July 31, 2019, thereby obviating the need for FERC to take any further action. Refer to Note 5 - Income Taxes for further discussion of the 2017 Tax Reform Act.
Empire filed a Section 4 rate case on June 29, 2018, proposing rate increases to be effective August 1, 2018. Empire and its customers reached a settlement in principle in December 2018, and Empire’s subsequent motion to put in place those interim settlement rates, effective January 1, 2019, was approved by FERC’s Chief Administrative Law Judge on December 31, 2018. The settlement remains subject to FERC approval. The “black box” settlement provides for new, system-wide rates, and which, based on current contracts, is estimated to increase Empire’s revenues on a yearly basis by approximately $4.6 million. The settlement also provides new depreciation rates and a tiered transportation revenue sharing mechanism, beginning with Empire sharing 35% of transportation only revenues (net of certain excluded items) over $64.4 million up to Empire sharing 55% of those revenues over $68.4 million. Empire has also committed to undertake certain improvements to its bulletin board and will convene regular customer meetings to address these and other improvements. Under the settlement, Empire and the other parties may not file to change rates until March 31, 2021, except that Empire may make a filing (to be effective November 1, 2020) under limited circumstances for contract changes with a large customer. Empire must file a Section 4 rate case no later than May 1, 2025.
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
OVERVIEW
Please note that this overview is a high-level summary of items that are discussed in greater detail in subsequent sections of this report.
The Company is a diversified energy company engaged principally in the production, gathering, transportation, distribution and marketing of natural gas. The Company operates an integrated business, with assets centered in western New York and Pennsylvania, being utilized for, and benefiting from, the production and transportation of natural gas from the Appalachian basin. Current development activities are focused primarily in the Marcellus and Utica Shale. The common geographic footprint of the Company’s subsidiaries enables them to share management, labor, facilities and support services across various businesses and pursue coordinated projects designed to produce and transport natural gas from the Appalachian basin to markets in Canada and the eastern United States. The Company's efforts in this regard are not limited to affiliated projects. The Company has also been designing and building pipeline projects for the transportation of natural gas for non-affiliated natural gas producers in the Appalachian basin. The Company also develops and produces oil reserves, primarily in California. The Company reports financial results for five business segments.
The Company's implementation of the 2017 Tax Reform Act had a significant impact on its financial statements. The effective tax rate for the quarter ended December 31, 2017 of negative 69.2% reflects a statutory rate of 24.5% as well as the impact of the remeasurement of the Company's accumulated deferred income taxes based upon the new tax rates established by the 2017 Tax Reform Act, which was recorded as a $111.0 million reduction to income tax expense during the quarter ended December 31, 2017. The effective tax rate for the quarter ended December 31, 2018 of 18.2% reflects a lower statutory rate of 21% as well as the impact of a $5.0 million reduction to income tax expense recorded during the quarter ended December 31, 2018. The $5.0 million reduction to income tax expense represents an adjustment to the fiscal 2018 remeasurement of the Company's accumulated deferred income taxes stemming from the 2017 Tax Reform Act. For further discussion of the impact of the 2017 Tax Reform Act to the Company, refer to Rate and Regulatory Matters below and to Item 1 at Note 5 — Income Taxes. For further discussion of the Company’s earnings, refer to the Results of Operations section below.
On February 3, 2017, the Company, in its Pipeline and Storage segment, received FERC approval of a project to move significant prospective Marcellus production from Seneca’s Western Development Area at Clermont to an Empire interconnection with TransCanada Pipeline at Chippawa and an interconnection with Tennessee Gas Pipeline’s 200 Line in East Aurora, New York (“Northern Access project”). 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, the Company appealed the NYDEC's decision with regard to the Water Quality Certification to the United States Court of Appeals for the Second Circuit, 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. The Company remains committed to the project. 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. Approximately $76.5 million in costs have been incurred on this project through December 31, 2018, with the costs residing either in Construction Work in Progress, a component of Property, Plant and Equipment on the Consolidated Balance Sheet, or Deferred Charges. For further discussion of the Northern Access project, refer to Item 1 at Note 7 — Commitments and Contingencies.
While legal proceedings continue on the Northern Access project, the Company continues to pursue development projects to expand its Pipeline and Storage segment. One project on Empire’s system, referred to as the Empire North Project, would allow for the transportation of 205,000 Dth per day of additional shale supplies from interconnections in Tioga County, Pennsylvania, to TransCanada Pipeline, and the TGP 200 Line. The Empire North Project has a projected in-service date in the second half of fiscal 2020 and an estimated cost of approximately $145 million. Another project on Supply Corporation’s system, referred to as the FM100 Project, is currently in the pre-filing process at FERC and will upgrade 1950’s era pipeline in northwestern Pennsylvania and create approximately 330,000 Dth per day of additional transportation capacity on Supply Corporation’s system in Pennsylvania from a receipt point with NFG Midstream Clermont, LLC in McKean County, Pennsylvania to the Transcontinental Gas Pipe Line Company, LLC system at Leidy, Pennsylvania. The FM100 Project has a target in-service date in late calendar 2021 and a preliminary cost estimate of approximately $280 million. These and other projects are discussed in more detail in the Capital Resources and Liquidity section that follows.