☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended December 31, 2020
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)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Trading Symbol
Name of Each Exchange
on Which Registered
Common Stock, par value $1.00 per share
NFG
New York Stock Exchange
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 (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes☑ 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☑ 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.
Large Accelerated Filer
☑
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 ☑
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, 2021: 91,163,446 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.
CLCPA
Legislation referred to as the "Climate Leadership & Community Protection Act," enacted by the State of New York on July 18, 2019.
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.
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.
Development costs
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)
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.
Open Season
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.
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.
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, 2020, 2019 and 2018 that are included in the Company's 2020 Form 10-K. The consolidated financial statements for the year ended September 30, 2021 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, 2020 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2021. Most of the business of the Utility segment is seasonal in nature and is influenced by weather conditions. Due to the seasonal nature of the heating business in the Utility segment, earnings during the winter months normally represent a substantial part of the earnings that this business is expected to achieve for the entire fiscal year. The Company’s business segments are discussed more fully in Note 9 – 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, 2020
Three Months Ended December 31, 2019
Balance at October 1, 2020
Balance at December 31, 2020
Balance at October 1, 2019
Balance at December 31, 2019
Cash and Temporary Cash Investments
$
20,541
$
109,413
$
20,428
$
34,966
Hedging Collateral Deposits
—
—
6,832
9,666
Cash, Cash Equivalents, and Restricted Cash
$
20,541
$
109,413
$
27,260
$
44,632
The Company considers all highly liquid debt instruments purchased with a maturity date of generally three months or less to be cash equivalents. The Company’s restricted cash is composed entirely of amounts reported as Hedging Collateral Deposits on the Consolidated Balance Sheets. Hedging Collateral Deposits is an account title for cash held in margin accounts funded by the Company to serve as collateral for hedging positions. In accordance with its accounting policy, the Company does not offset hedging collateral deposits paid or received against related derivative financial instruments liability or asset balances.
Allowance for Uncollectible Accounts. The allowance for uncollectible accounts is the Company’s best estimate of the amount of probable credit losses in the existing accounts receivable. The allowance is determined based on historical experience, the age of customer accounts, other specific information about customer accounts, and the economic environment. Account balances are charged off against the allowance twelve months after the account is final billed or when it is anticipated that the receivable will not be recovered. In response to the COVID-19 pandemic, the Company has suspended collection and termination activity for non-payments in its Utility service territories. To date, despite the economic conditions that have arisen as a result of the COVID-19 pandemic, the Company has not experienced a significant reduction in the rate at which its customers pay their bills. However, as the winter heating season progresses, the Company is anticipating that customer non-payment may increase given higher natural gas usage and the resulting increase in costs for customers.
Activity in the allowance for uncollectible accounts for the three months ended December 31, 2020 are as follows:
Balance at Beginning of Period
Additions Charged to Costs and Expenses
Add: Discounts on Purchased Receivables
Deduct: Net Accounts Receivable Written-Off
Balance at End of Period
Three Months Ended December 31, 2020
Allowance for Uncollectible Accounts
$
22,810
$
4,679
$
170
$
1,438
$
26,221
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 $1.8 million at December 31, 2020, is reduced to zero by September 30 of each year as the inventory is replenished.
Materials, Supplies and Emission Allowances. The components of the Company's materials, supplies and emission allowances are as follows:
At December 31, 2020
At September 30, 2020
Materials and Supplies - at average cost
$
33,676
$
33,859
Emission Allowances
18,018
18,018
$
51,694
$
51,877
Property, Plant and Equipment. In the Company’s Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. The Company's capitalized costs relating to oil and gas producing activities, net of accumulated depreciation, depletion and amortization, were $1.7 billion and $1.8 billion at December 31, 2020 and September 30, 2020, respectively.
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 $134.9 million and $148.1 million at December 31, 2020 and September 30, 2020, 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 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 non-cash impairment is required to be charged to earnings in that quarter. The book value of the oil and gas properties exceeded the ceiling at December 31, 2020. As such, the Company recognized a non-cash, pre-tax impairment charge of $76.2 million for the quarter ended December 31, 2020. A deferred income tax benefit of $21.0 million related to the non-cash impairment charge was also recognized for the quarter ended December 31, 2020. In
adjusting estimated future cash flows for hedging under the ceiling test at December 31, 2020, estimated future net cash flows were increased by $183.0 million.
The principal assets of the Utility, Pipeline and Storage and Gathering segments, consisting primarily of gas distribution pipelines, transmission pipelines, storage facilities, gathering lines and compressor stations, are recorded at historical cost. Despite the economic conditions arising from the COVID-19 pandemic, there were no indications of any impairments to property, plant and equipment in the Utility, Pipeline and Storage and Gathering segments at December 31, 2020. Management will continue to monitor the situation on a quarterly basis.
Accumulated Other Comprehensive Income (Loss).The components of Accumulated Other Comprehensive Income (Loss) and changes for the three months ended December 31, 2020 and 2019, net of related tax effect, are as follows (amounts in parentheses indicate debits) (in thousands):
Gains and Losses on Derivative Financial Instruments
Funded Status of the Pension and Other Post-Retirement Benefit Plans
Total
Three Months Ended December 31, 2020
Balance at October 1, 2020
$
(24,865)
$
(89,892)
$
(114,757)
Other Comprehensive Gains and Losses Before Reclassifications
34,791
—
34,791
Amounts Reclassified From Other Comprehensive Income (Loss)
225
—
225
Balance at December 31, 2020
$
10,151
$
(89,892)
$
(79,741)
Three Months Ended December 31, 2019
Balance at October 1, 2019
$
34,675
$
(86,830)
$
(52,155)
Other Comprehensive Gains and Losses Before Reclassifications
376
—
376
Amounts Reclassified From Other Comprehensive Income (Loss)
(5,321)
—
(5,321)
Cumulative Effect of Adoption of Authoritative Guidance for Hedging
950
—
950
Balance at December 31, 2019
$
30,680
$
(86,830)
$
(56,150)
In August 2017, the FASB issued authoritative guidance which changed the financial reporting of hedging relationships to better portray the economic results of an entity's risk management activities and to simplify the application of hedge accounting. The Company adopted this authoritative guidance effective October 1, 2019, recognizing a cumulative effect adjustment that decreased retained earnings by $1.0 million and increased accumulated other comprehensive income by the same amount.
Reclassifications Outof Accumulated Other Comprehensive Income (Loss). The details about the reclassification adjustments out of accumulated other comprehensive income (loss) for the three months ended December 31, 2020 and 2019 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands):
Details About Accumulated Other Comprehensive Income (Loss) Components
Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss)
Affected Line Item in the Statement Where Net Income is Presented
Three Months Ended December 31,
2020
2019
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
Commodity Contracts
($310)
$7,541
Operating Revenues
Commodity Contracts
—
2
Purchased Gas
Foreign Currency Contracts
(1)
(191)
Operating Revenues
(311)
7,352
Total Before Income Tax
86
(2,031)
Income Tax Expense
($225)
$5,321
Net of Tax
Other Current Assets. The components of the Company’s Other Current Assets are as follows (in thousands):
At December 31, 2020
At September 30, 2020
Prepayments
$
10,203
$
12,851
Prepaid Property and Other Taxes
14,821
14,269
State Income Taxes Receivable
1,439
3,828
Regulatory Assets
21,441
16,609
$
47,904
$
47,557
Other Accruals and Current Liabilities. The components of the Company’s Other Accruals and Current Liabilities are as follows (in thousands):
At December 31, 2020
At September 30, 2020
Accrued Capital Expenditures
$
34,840
$
33,344
Regulatory Liabilities
41,402
44,890
Reserve for Gas Replacement
1,778
—
Liability for Royalty and Working Interests
22,869
15,665
Non-Qualified Benefit Plan Liability
14,460
14,460
Other
39,028
31,817
$
154,377
$
140,176
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, 2020, 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 373,378 securities and 733,617 securities excluded as being antidilutive for the quarters ended December 31, 2020 and December 31, 2019, respectively.
Stock-Based Compensation. The Company granted 309,470 performance shares during the quarter ended December 31, 2020. The weighted average fair value of such performance shares was $39.19 per share for the quarter ended December 31, 2020. 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, 2020 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, 2020 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 170,113 restricted stock units during the quarter ended December 31, 2020. The weighted average fair value of such restricted stock units was $38.00 per share for the quarter ended December 31, 2020. 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 restricted stock units do not entitle the participant to receive dividends during the vesting period. The accounting for 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. On October 1, 2020, the Company adopted authoritative guidance regarding the measurement of credit losses on financial assets measured at amortized cost. The new guidance requires financial assets measured at amortized cost to be presented at the net amount expected to be collected, which means that companies are required to recognize an allowance for credit losses for the difference between the amortized cost basis of the financial asset and the amount expected to be collected over the contractual life of the asset. Prior to adoption, the Company analyzed its financial assets measured at amortized cost, primarily trade receivables. The adoption of this guidance did not have a material impact to the Company’s financial statements.
On December 10, 2020, the Company completed the sale of substantially all timber properties in Pennsylvania to Lyme Emporium Highlands III LLC and Lyme Allegheny Land Company II LLC for net proceeds of $104.6 million. At September 30, 2020, these assets, amounting to $53.4 million, which previously were recorded as Net Property, Plant and Equipment, were presented as Assets Held for Sale, Net on the Consolidated Balance Sheet. The assets were a component of the Company’s All Other category and did not have a major impact on the Company’s operations or financial results. After purchase price adjustments and transaction costs, a gain of $51.1 million was recognized on the sale of these assets. Since the sale did not represent a strategic shift in focus for the Company, the financial results associated with operating these assets as well as the gain on sale have not been reported as discontinued operations.
The sale of the timber properties completed a reverse like-kind exchange pursuant to Section 1031 of the Internal Revenue Code, as amended (“Reverse 1031 Exchange”). On July 31, 2020, the Company completed its acquisition of certain upstream assets and midstream gathering assets in Pennsylvania from SWEPI LP, a subsidiary of Royal Dutch Shell plc (“Shell”) for total consideration of $506.3 million. The purchase and sale agreement with Shell was structured, in part, as a Reverse 1031 Exchange. In connection with the Reverse 1031 Exchange, the Company, through a subsidiary, assigned the rights to acquire legal title to certain oil and natural gas properties to a Variable Interest Entity ("VIE") formed by an exchange accommodation titleholder. From July 31, 2020 to December 10, 2020, a subsidiary of the Company operated the properties pursuant to a lease agreement with the VIE. As the Company was deemed to be the primary beneficiary of the VIE, the VIE was included in the consolidated financial statements of the Company. Upon completion of the sale of the timber properties on December 10, 2020, the affected properties were conveyed to the Company and the VIE structure was terminated. Refer to Note B – Asset Acquisitions and Divestitures of the Company’s 2020 Form 10-K for additional information concerning the Company’s acquisition of certain upstream assets and midstream gathering assets from Shell.
Note 3 – Revenue from Contracts with Customers
The following tables provide a disaggregation of the Company's revenues for the three months ended December 31, 2020 and 2019, presented by type of service from each reportable segment.
The Company records revenue related to its derivative financial instruments in the Exploration and Production segment as well as in its NFR operations (included in the All Other category). The Company discontinued use of derivative financial instruments in its NFR operations upon completing the sale of its commercial and industrial contracts and certain other assets on August 1, 2020. The Company has been winding down its NFR operations since August 1, 2020 which has resulted in a significant reduction in natural gas marketing revenues as shown in the tables above. 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 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: $142.5 million for the remainder of fiscal 2021; $170.7 million for fiscal 2022; $134.7 million for fiscal 2023; $123.5 million for fiscal 2024; $117.0 million for fiscal 2025; and $517.5 million thereafter.
Note 4 – 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, 2020 and September 30, 2020. 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, 2020
(Thousands of Dollars)
Level 1
Level 2
Level 3
Netting
Adjustments(1)
Total(1)
Assets:
Cash Equivalents – Money Market Mutual Funds
$
89,114
$
—
$
—
$
—
$
89,114
Derivative Financial Instruments:
Over the Counter Swaps – Gas and Oil
—
37,571
—
(19,204)
18,367
Over the Counter No Cost Collars – Gas
—
—
—
(444)
(444)
Foreign Currency Contracts
—
1,027
—
(856)
171
Other Investments:
Balanced Equity Mutual Fund
32,226
—
—
—
32,226
Fixed Income Mutual Fund
70,223
—
—
—
70,223
Common Stock – Financial Services Industry
819
—
—
—
819
Total
$
192,382
$
38,598
$
—
$
(20,504)
$
210,476
Liabilities:
Derivative Financial Instruments:
Over the Counter Swaps – Gas and Oil
—
22,966
—
(19,204)
3,762
Over the Counter No Cost Collars – Gas
—
1,734
—
(444)
1,290
Foreign Currency Contracts
—
317
—
(856)
(539)
Total
$
—
$
25,017
$
—
$
(20,504)
$
4,513
Total Net Assets/(Liabilities)
$
192,382
$
13,581
$
—
$
—
$
205,963
Recurring Fair Value Measures
At fair value as of September 30, 2020
(Thousands of Dollars)
Level 1
Level 2
Level 3
Netting
Adjustments(1)
Total(1)
Assets:
Cash Equivalents – Money Market Mutual Funds
$
12,285
$
—
$
—
$
—
$
12,285
Derivative Financial Instruments:
Over the Counter Swaps – Gas and Oil
—
36,418
—
(26,400)
10,018
Over the Counter No Cost Collars – Gas
—
—
—
(720)
(720)
Foreign Currency Contracts
—
259
—
(338)
(79)
Other Investments:
Balanced Equity Mutual Fund
39,618
—
—
—
39,618
Fixed Income Mutual Fund
72,253
—
—
—
72,253
Common Stock – Financial Services Industry
639
—
—
—
639
Total
$
124,795
$
36,677
$
—
$
(27,458)
$
134,014
Liabilities:
Derivative Financial Instruments:
Over the Counter Swaps – Gas and Oil
—
61,280
—
(26,400)
34,880
Over the Counter No Cost Collars – Gas
—
8,171
—
(720)
7,451
Foreign Currency Contracts
—
1,976
—
(338)
1,638
Total
$
—
$
71,427
$
—
$
(27,458)
$
43,969
Total Net Assets/(Liabilities)
$
124,795
$
(34,750)
$
—
$
—
$
90,045
(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.
The derivative financial instruments reported in Level 2 at December 31, 2020 and September 30, 2020 consist of natural gas price swap agreements, natural gas no cost collars, crude oil price swap agreements, and foreign currency contracts, all of which are used in the Company’s Exploration and Production segment. The fair value of the Level 2 price swap agreements and no cost collars 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, 2020, 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, 2020 and December 31, 2019, there were no assets or liabilities measured at fair value and classified as Level 3.
Note 5 – 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, 2020
September 30, 2020
Carrying Amount
Fair Value
Carrying Amount
Fair Value
Long-Term Debt
$
2,630,473
$
2,868,429
$
2,629,576
$
2,778,556
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, 2020
At September 30, 2020
Life Insurance Contracts
$
42,653
$
41,992
Equity Mutual Fund
32,226
39,618
Fixed Income Mutual Fund
70,223
72,253
Marketable Equity Securities
819
639
$
145,921
$
154,502
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. The Company enters into over-the-counter no cost collars 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 duration of the Company’s cash flow hedges does not typically exceed 5 years while the foreign currency forward contracts do not exceed 10 years.
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, 2020 and September 30, 2020. 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 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.
As of December 31, 2020, the Company had the following commodity derivative contracts (swaps and no cost collars) outstanding:
Commodity
Units
Natural Gas
282.0
Bcf
Crude Oil
1,605,000
Bbls
As of December 31, 2020, the Company was hedging a total of $73.7 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts.
As of December 31, 2020, the Company had $13.6 million ($10.2 million after-tax) of net hedging gains included in the accumulated other comprehensive income (loss) balance. It is expected that $3.3 million ($2.4 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, 2020 and 2019 (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) 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
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income for the Three Months Ended December 31,
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, no cost collars and applicable foreign currency forward contracts with sixteen counterparties of which ten are in a net gain position. On average, the Company had $1.8 million of credit exposure per counterparty in a gain position at December 31, 2020. The maximum credit exposure per counterparty in a gain position at December 31, 2020 was $4.2 million. As of December 31, 2020, 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, 2020, fourteen of the sixteen counterparties to the Company’s outstanding derivative instrument contracts (specifically the over-the-counter swaps, over-the-counter no cost collars 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, 2020, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $14.4 million according to the Company’s internal model (discussed in Note 4 – Fair Value Measurements). At December 31, 2020, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $4.5 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, 2020.
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.
Note 6 – Income Taxes
The effective tax rates for the quarters ended December 31, 2020 and December 31, 2019 were 27.4% and 26.6%, respectively. The increase in the tax rate is primarily the result of the valuation allowance recorded against certain state deferred tax assets, discussed below, differences between the book and tax treatment of stock compensation, and a decrease in the allowance for funds used during construction (which is not taxable) as a result of certain ongoing projects in the Company's Pipeline and Storage segment being placed in service in fiscal 2020.
A valuation allowance for deferred tax assets, including net operating losses and tax credits, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. The Company continually assesses the realizability of its deferred tax assets, including factors such as future taxable income, reversal of existing temporary differences, and tax planning strategies. The Company considers both positive and negative evidence related to the likelihood of the realization of the deferred tax assets. As of March 31, 2020, the Company recorded a valuation allowance against certain state deferred tax assets in the amount of $56.8 million based on its conclusion, considering all available objective evidence and the Company’s history of subsidiary state tax losses, that it was more likely than not that the deferred tax assets would not be realized. The valuation allowance increased to $63.6 million as of December 31, 2020 as a result of certain state net operating loss and tax credit activity. Changes in judgment regarding future realization of these deferred tax assets may result in a reversal of all or a portion of the valuation allowance. The Company will continue to re-assess this position each quarter.
On March 27, 2020, the “Coronavirus Aid, Relief and Economic Security (CARES) Act” was signed into law.The CARES Act, among other things, includes provisions relating to AMT credit refunds, refundable payroll tax credits, deferment of employer side social security payments, net operating loss carryback periods, and modifications to the net interest deduction limitation. The 2017 Tax Reform Act had repealed the corporate alternative minimum tax and provided that the Company’s existing AMT credit carryovers were refundable over a four year period. As of September 30, 2018, the Company had $85.0 million of AMT credit carryovers. The Company received the first installment for $42.5 million of AMT credit refunds related
to fiscal 2019 in January 2020 and filed for the acceleration of the remaining AMT credit refunds of $42.5 million, which were received in June 2020.
On December 27, 2020, the “Consolidated Appropriations Act, 2021 (CAA)” was signed into law. The CAA clarifies and expands the Paycheck Protection Program loans and the Employee Retention Credit as well as several other tax provisions first outlined in the CARES Act. The CAA is currently being evaluated, however, the Company does not anticipate a material impact as a result of this legislation.
Note 7 –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, 2020
90,955
$
90,955
$
1,004,158
$
991,630
$
(114,757)
Net Income Available for Common Stock
77,774
Dividends Declared on Common Stock ($0.445 Per Share)
(40,560)
Other Comprehensive Income, Net of Tax
35,016
Share-Based Payment Expense (1)
3,496
Common Stock Issued (Repurchased) Under Stock and Benefit Plans
198
198
(3,285)
Balance at December 31, 2020
91,153
$
91,153
$
1,004,369
$
1,028,844
$
(79,741)
Balance at October 1, 2019
86,315
$
86,315
$
832,264
$
1,272,601
$
(52,155)
Net Income Available for Common Stock
86,591
Dividends Declared on Common Stock ($0.435 Per Share)
(37,650)
Cumulative Effect of Adoption of Authoritative Guidance for Hedging
(950)
Other Comprehensive Loss, Net of Tax
(3,995)
Share-Based Payment Expense (1)
2,828
Common Stock Issued (Repurchased) Under Stock and Benefit Plans
237
237
(3,946)
Balance at December 31, 2019
86,552
$
86,552
$
831,146
$
1,320,592
$
(56,150)
(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, 2020, the Company issued 104,760 original issue shares of common stock for restricted stock units that vested and 165,161 original issue shares of common stock for performance shares that vested. The Company also issued 10,880 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, 2020. 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, 2020, 82,787 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. Current Portion of Long-Term Debt at December 31, 2020 consists of $500.0 million of 4.90% notes that mature in December 2021. None of the Company's long-term debt as of September 30, 2020 had a maturity date within the following twelve-month period.
Short-Term Borrowings. On February 3, 2021, the Company amended its existing 364-day credit facility agreement. The amendment extends the maturity date of the facility from May 3, 2021 to December 30, 2022, and increases the commitment provided under the facility from $200.0 million to $250.0 million of unsecured committed revolving credit access. The
Company entered into the amendment with a syndicate of twelve banks, all of which are also lenders under the Company's existing $750.0 million multi-year credit facility.
Note 8 – 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, 2020, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $6.0 million, which includes a $3.1 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, 2020. The Company expects to recover its environmental clean-up costs through rate recovery over a period of approximately 2 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. Shortly thereafter, 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 in January of 2017). The United States Court of Appeals for the Second Circuit (the “Second Circuit Court of Appeals”) held in the Company’s favor in its appeal of this decision, vacating the NYDEC denial and remanding to the NYDEC. The NYDEC subsequently issued a second denial, which the Company has appealed to the Second Circuit Court of Appeals. The court has held this appeal in abeyance pending the outcome of the FERC waiver appeal, described below. While the Company’s initial appeal was pending before the Second Circuit Court of Appeals, 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. FERC denied rehearing requests associated with its Order and FERC's decisions have been appealed and are pending in a separate action before the Second Circuit Court of Appeals. In addition, in the Company's state court litigation challenging the NYDEC's actions with regard to various state permits, the New York State Supreme Court issued a decision finding these permits to be preempted. The Company remains committed to the project.
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 9 – Business Segment Information
The Company reports financial results for four segments: Exploration and Production, Pipeline and Storage, Gathering and Utility. 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 2020 Form 10-K, the Company evaluates segment performance based on income before discontinued operations (when applicable). When this is 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 2020 Form 10-K. A listing of segment assets at December 31, 2020 and September 30, 2020 is shown in the tables below.
Note 10 – 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,
2020
2019
2020
2019
Service Cost
$
2,466
$
2,330
$
400
$
402
Interest Cost
5,422
7,483
2,326
3,228
Expected Return on Plan Assets
(14,537)
(15,016)
(7,241)
(7,308)
Amortization of Prior Service Cost (Credit)
158
182
(107)
(107)
Amortization of Losses
9,203
9,846
212
134
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)
3,713
1,527
6,854
6,249
Net Periodic Benefit Cost
$
6,425
$
6,352
$
2,444
$
2,598
(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.
The components of net periodic benefit cost other than service cost are presented in Other Income (Deductions) on the Consolidated Statements of Income.
Employer Contributions. During the three months ended December 31, 2020, the Company contributed $5.2 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 2021, the Company expects its contributions to the Retirement Plan to be in the range of $10.0 million to $20.0 million. In the remainder of 2021, the Company expects its contributions to its VEBA trusts to be in the range of $2.0 million to $2.5 million.
Note 11– Regulatory Matters
New YorkJurisdiction
Distribution Corporation's current delivery rates in its New York jurisdiction were approved by the NYPSC in an order issued on April 20, 2017 with rates becoming effective May 1, 2017. The order provided for a return on equity of 8.7%. The order also directed the implementation of an earnings sharing mechanism to be in place beginning on April 1, 2018.
In New York, on March 13, 2020, in response to the COVID-19 pandemic, the Company agreed to NYPSC Staff’s request that the Company suspend service terminations and disconnections. Thereafter, on June 17, 2020, New York enacted a new law that prohibits utilities from terminating or disconnecting services to any residential customer for non-payment for the duration of the state disaster emergency. In addition, the law prohibits residential terminations for non-payment for a period of 180 days running from the end of the state disaster emergency for customers that have experienced a change in financial circumstances due to the COVID-19 state of emergency. Governor Cuomo, through the issuance of executive orders, has extended the declaration of the state disaster emergency through February 26, 2021. The law currently sunsets on March 31, 2021, but legislation extending the moratorium is anticipated. The duration of the aforementioned suspension in New York and its related impact on the Company is uncertain. The Company is anticipating that customer non-payment may increase given higher natural gas usage and the resulting increase in costs for customers. It is uncertain at this point as to whether there would be any regulatory relief for utilities with regard to an increase in costs associated with the COVID-19 pandemic, but it is one of many issues currently being considered in a generic NYPSC proceeding entitled “Proceeding on Motion of the Commission Regarding the Effects of COVID-19 on Utility Service” (Case No. 20-M-0266). Correspondence from NYPSC Staff has recommended that utilities rely on existing avenues of relief for these costs, and has identified additional, more stringent requirements that must be met to achieve relief.
Pennsylvania Jurisdiction
Distribution Corporation’s current delivery rates in its Pennsylvania jurisdiction were approved by the PaPUC on November 30, 2006 as part of a settlement agreement that became effective January 1, 2007. The rate settlement does not specify any requirement to file a future rate case.
On March 26, 2020, the PaPUC ratified an Emergency Order that established a Service Termination Moratorium intended to continue during the pendency of Governor Wolf’s March 6, 2020 Proclamation of Disaster Emergency associated with the COVID-19 pandemic. On May 13, 2020, the Company (and other Pennsylvania local distribution companies) received a Secretarial Letter from the PaPUC regarding COVID-19 pandemic cost tracking and regulatory assets. The Secretarial Letter directs utilities to track “extraordinary, nonrecurring incremental COVID-19 related expenses” so the Commission can understand the impact of these expenses on the utilities’ finances. It also authorizes the creation of a utility regulatory asset, but only for incremental uncollectible expenses incurred above those embedded in rates (and incurred since the issuance of the Emergency Order). The Company currently does not anticipate a need to create a regulatory asset for these expenses. On October 8, 2020, the Commission issued an order ending the moratorium effective November 9, 2020, imposing a list of enhanced customer protections that expire on March 31, 2021 and calling for comments by February 16, 2021 regarding policies the Commission should adopt after March 31, 2021. The order also appears to expand the aforementioned potential utility regulatory asset to all incremental COVID-19 related expenses incurred above those embedded in rates. The Company continues to monitor this item for potential deferral opportunity.
FERC Jurisdiction
Supply Corporation’s rate settlement, approved June 1, 2020, provides that no party may make a rate filing for new rates to be effective before February 1, 2024, except that Supply Corporation may file an NGA general Section 4 rate case to change rates if the corporate federal income tax rate is increased. If no case has been filed, Supply Corporation must file for rates to be effective February 1, 2025. Supply has no rate case currently on file.
Empire’s 2019 rate settlement provides that no party may make a filing for new rates before March 31, 2021. If no rate case has been filed, Empire must make a rate case filing 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 and distribution 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 shales. 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 the eastern United States and Canada. 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 four business segments. For a discussion of the Company's earnings, refer to the Results of Operations section below.
The Company is closely monitoring and responding to developments related to the novel coronavirus (COVID-19) and is taking steps to limit operational impacts and the potential exposure for our workforce and customers. Refer to Risk Factors in Item 1A of this Form 10-Q as well as Part I, Item 1A, Risk Factors, under Operational Risks in the Company's 2020 Form 10-K for a more complete discussion of the risks to the Company associated with the COVID-19 pandemic.
The Company uses the full cost method of accounting for determining the book value of its oil and natural gas properties in the Exploration and Production segment and that book value is subject to a quarterly ceiling test. This is discussed in more detail in the Critical Accounting Estimates section that follows. In addition to the significant non-cash impairment charges under the ceiling test that the Company recorded during fiscal 2020, the Company recorded a non-cash impairment charge under the ceiling test for the quarter ended December 31, 2020 of $76.2 million ($55.2 million after-tax). Given the significant non-cash impairments recorded during fiscal 2020 and in the first quarter of fiscal 2021, under its existing indenture covenants contained in the Company's 1974 indenture, the Company is precluded from issuing incremental unsubordinated long-term indebtedness for a period beginning in January 2021 and expected to extend into the second half of fiscal 2021. However, the Company expects that it could borrow under its existing credit facilities. Additionally, the 1974 indenture would not preclude the Company from issuing new indebtedness to refund existing debt. Please refer to the Critical Accounting Estimates section below for a sensitivity analysis concerning commodity price changes.
In advance of the expected late calendar 2021 online date for Seneca’s 330,000 decatherms per day of incremental capacity on the Leidy South Project, the Company's Exploration and Production segment added a second horizontal drilling rig in the Appalachian region in January 2021. Production from the first pad that will be drilled in connection with this additional activity is expected in early fiscal 2022, allowing Seneca to utilize its incremental capacity to reach premium markets during the winter heating season.
On December 10, 2020, the Company completed the sale of substantially all timber properties in Pennsylvania to Lyme Emporium Highlands III LLC and Lyme Allegheny Land Company II LLC for net proceeds of $104.6 million. After purchase price adjustments and transaction costs, a gain of $51.1 million was recognized on the sale of these assets ($37.0 million after-tax). Refer to Note 2 – Asset Acquisitions and Divestitures for additional information concerning this sale.
On February 3, 2021, the Company amended its existing 364-day credit facility agreement. The amendment extends the maturity date of the facility from May 3, 2021 to December 30, 2022, and increases the commitment provided under the facility from $200.0 million to $250.0 million of unsecured committed revolving credit access. The Company entered into the amendment with a syndicate of twelve banks, all of which are also lenders under the Company's existing $750.0 million multi-year credit facility.
The sale of timber properties discussed above, combined with cash on hand, cash from operations and short-term borrowings, are expected to meet the Company’s financing needs for fiscal 2021. The Company plans to issue long-term debt during fiscal 2021 to replace all or a portion of its December 2021 debt maturity.
The Company continues to pursue development projects to expand its Pipeline and Storage segment. The Company is monitoring the impacts of the COVID-19 pandemic on its supply chains and development projects in this segment. To date, the
COVID-19 pandemic has not had a material impact on the target in-service dates of these development projects. However, the unpredictable extent and duration of the pandemic, and the government imposition of certain significant restrictions associated therewith, could delay receipt of necessary equipment or delay construction. The Company will continue to monitor this rapidly evolving situation and mitigate where possible. One project on Empire’s system, referred to as the Empire North Project, which allows for the transportation of 205,000 Dth per day of additional shale supplies from interconnections in Tioga County, Pennsylvania, to the TC Energy pipeline, and the TGP 200 Line, was placed in-service during the fourth quarter of fiscal 2020. Another project on Supply Corporation’s system, referred to as the FM100 Project, will upgrade a 1950’s era pipeline in northwestern Pennsylvania and create approximately 330,000 Dth per day of additional transportation capacity 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 of late calendar 2021 and a preliminary cost estimate of approximately $280 million. This project is discussed in more detail in the Capital Resources and Liquidity section that follows.
From a legislation perspective, in July 2019, New York State enacted legislation known as the Climate Leadership & Community Protection Act (CLCPA). This climate legislation mandates reducing greenhouse gas emissions to 60% of 1990 levels by 2030, and to 15% of 1990 levels by 2050, with the remaining emission reduction achieved by controlled offsets. The legislation also requires electric generators to meet 70% of demand with renewable energy by 2030 and 100% with zero emissions generation by 2040. The CLCPA established a climate action council and a series of advisory panels and working groups to study how the state will achieve the aggressive emission reduction targets. Thus far, the only regulations promulgated in connection with the CLCPA are greenhouse gas limits established by the NYDEC on December 30, 2020. For further discussion of the CLCPA, refer to the Environmental Matters section below.
CRITICAL ACCOUNTING ESTIMATES
For a complete discussion of critical accounting estimates, refer to "Critical Accounting Estimates" in Item 7 of the Company's 2020 Form 10-K. There have been no material changes to that disclosure other than as set forth below. The information presented below updates and should be read in conjunction with the critical accounting estimates in that Form 10-K.
Oil and Gas Exploration and Development Costs. The Company, in its Exploration and Production segment, follows the full cost method of accounting for determining the book value of its oil and natural gas properties. In accordance with this methodology, the Company is required to perform a quarterly ceiling test. Under the ceiling test, the present value of future revenues from the Company's oil and gas reserves 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 (the “ceiling”) is compared with the book value of the Company’s oil and gas properties at the balance sheet date. The present value of future revenues is calculated using a 10% discount factor. If the book value of the oil and gas properties exceeds the ceiling, a non-cash impairment charge must be recorded to reduce the book value of the oil and gas properties to the calculated ceiling. The book value of the oil and gas properties exceeded the ceiling at December 31, 2020, resulting in a non-cash impairment charge of $76.2 million ($55.2 million after-tax) for the quarter ended December 31, 2020. The 12-month average of the first day of the month price for crude oil for each month during the twelve months ended December 31, 2020, based on posted Midway Sunset prices, was $38.31 per Bbl. The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended December 31, 2020, based on the quoted Henry Hub spot price for natural gas, was $1.99 per MMBtu. (Note: Because actual pricing of the Company’s producing properties vary depending on their location and hedging, the prices used to calculate the ceiling may differ from the Midway Sunset and Henry Hub prices, which are only indicative of 12-month average prices for the twelve months ended December 31, 2020. Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.) The following table illustrates the sensitivity of the ceiling test calculation to commodity price changes, specifically showing the additional non-cash impairment that the Company would have recorded at December 31, 2020 if natural gas prices were $0.25 per MMBtu lower than the average prices used at December 31, 2020, the additional non-cash impairment that the Company would have recorded at December 31, 2020 if crude oil prices were $5 per Bbl lower than the average prices used at December 31, 2020, and the additional non-cash impairment that the Company would have recorded at December 31, 2020 if both natural gas prices and crude oil prices were $0.25 per MMBtu and $5 per Bbl lower than the average prices used at December 31, 2020 (all amounts are presented after-tax). These calculated amounts are based solely on price changes and do not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates.
Ceiling Testing Sensitivity to Commodity Price Changes
(Millions)
$0.25/MMBtu Decrease in Natural Gas Prices
$5.00/Bbl Decrease in Crude Oil Prices
$0.25/MMBtu Decrease in Natural Gas Prices and $5.00/Bbl Decrease in Crude Oil Prices
Calculated Impairment under Sensitivity Analysis
$
325.3
$
91.0
$
361.1
Actual Impairment Recorded at December 31, 2020
55.2
55.2
55.2
Additional Impairment
$
270.1
$
35.8
$
305.9
It is difficult to predict what factors could lead to future non-cash impairments under the SEC's full cost ceiling test. Fluctuations in or subtractions from proved reserves, increases in development costs for undeveloped reserves and significant fluctuations in oil and gas prices have an impact on the amount of the ceiling at any point in time. For a more complete discussion of the full cost method of accounting, refer to "Oil and Gas Exploration and Development Costs" under "Critical Accounting Estimates" in Item 7 of the Company's 2020 Form 10-K.
RESULTS OF OPERATIONS
Earnings
The Company's earnings were $77.8 million for the quarter ended December 31, 2020 compared to earnings of $86.6 million for the quarter ended December 31, 2019. The decrease in earnings is primarily the result of a loss recognized in the Exploration and Production segment. Lower earnings in the Utility segment also contributed to the decrease. Higher earnings in the Pipeline and Storage segment, Gathering segment and Corporate and All Other categories partially offset these decreases.
The Company's earnings for the quarter ended December 31, 2020 include a non-cash $76.2 million impairment charge ($55.2 million after-tax) recorded during the quarter ended December 31, 2020 for the Exploration and Production segment's oil and gas producing properties, as discussed above. The Company's earnings for the quarter ended December 31, 2020 also include a gain recognized on the sale of timber properties of $51.1 million ($37.0 million after-tax) in the Company's All Other category, as discussed above. Additional discussion of earnings in each of the business segments can be found in the business segment information that follows. Note that all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted.
Operating revenues for the Exploration and Production segment increased $25.5 million for the quarter ended December 31, 2020 as compared with the quarter ended December 31, 2019. Gas production revenue after hedging increased $35.3 million due to the impact of a 21.3 Bcf increase in natural gas production, which was partially offset by a $0.18 per Mcf decrease in the weighted average price of natural gas after hedging. Natural gas production increased, despite approximately 4 Bcf of price-related curtailments, largely due to additional production from the Company's fourth quarter fiscal 2020 acquisition of Appalachian upstream assets from Shell coupled with new Marcellus and Utica wells in the Western and Eastern Development Area in the Appalachian region. Oil production revenue after hedging decreased $9.7 million due to a $13.01 per Bbl decrease in the weighted average price of oil after hedging, coupled with the impact of a 38 Mbbl decrease in oil production. The decrease in oil production was largely due to natural declines in the West Coast region.
The Exploration and Production segment's loss for the quarter ended December 31, 2020 was $29.6 million, a decrease of $53.6 million when compared with earnings of $24.0 million for the quarter ended December 31, 2019. The loss can be attributed to a non-cash impairment of oil and gas properties ($55.2 million), lower natural gas prices after hedging ($11.3 million), lower oil production ($1.9 million), lower oil prices after hedging ($5.8 million), higher depletion expense ($0.9 million), higher lease operating and transportation expenses ($11.7 million), higher other operating expenses ($1.8 million), higher interest expense ($1.1 million) and a higher effective tax rate ($3.2 million). The earnings impact of these items was partially offset by higher natural gas production ($39.2 million), as discussed above. The increase in depletion expense was primarily due to the net increase in production offset by a $0.19 per Mcf decrease in the depletion rate due to prior year non-cash ceiling test impairments coupled with the impact of the asset acquisition from Shell. The increase in lease operating and transportation expenses was largely attributed to higher natural gas production. The increase in other operating expenses was largely due to increases in accretion costs associated with asset retirement obligations coupled with higher compensation and personnel costs. The increase in interest expense was primarily due to interest on additional intercompany long-term borrowings associated with the Company's June 2020 debt issuance.
Pipeline and Storage
Pipeline and Storage Operating Revenues
Three Months Ended December 31,
(Thousands)
2020
2019
Increase (Decrease)
Firm Transportation
$
64,599
$
53,191
$
11,408
Interruptible Transportation
226
261
(35)
64,825
53,452
11,373
Firm Storage Service
20,485
18,420
2,065
Interruptible Storage Service
32
6
26
Other
2,422
342
2,080
$
87,764
$
72,220
$
15,544
Pipeline and Storage Throughput
Three Months Ended December 31,
(MMcf)
2020
2019
Increase (Decrease)
Firm Transportation
203,028
208,648
(5,620)
Interruptible Transportation
590
714
(124)
203,618
209,362
(5,744)
2020 Compared with 2019
Operating revenues for the Pipeline and Storage segment increased $15.5 million for the quarter ended December 31, 2020 as compared with the quarter ended December 31, 2019. The increase in operating revenues was primarily due to an increase in transportation revenues of $11.4 million, an increase in storage revenues of $2.1 million and an increase in other
revenues of $2.1 million. The increase in transportation revenues was partially attributable to an increase in Supply Corporation's transportation and storage rates effective February 1, 2020 in accordance with Supply Corporation's rate case settlement. The settlement was approved by the FERC on June 1, 2020. Transportation revenues also increased due to new demand charges for transportation service from the Empire North project, which was placed into service during the fourth quarter of fiscal 2020 and Supply Corporation's Line N to Monaca Project that went into service in November 2019. The increase in transportation revenues was partially offset by contract terminations and restructurings and also by a decrease in revenues from short-term seasonal contracts. The increase in storage revenues was also primarily attributable to the increase in Supply Corporation's rates related to its rate case settlement discussed above. The increase in other revenues was primarily due to proceeds received during the quarter ended December 31, 2020 as a result of a contract buyout.
Transportation volume for the quarter ended December 31, 2020 decreased by 5.7 Bcf from the prior year's quarter, primarily due to warmer weather than the prior year, a decline in capacity utilization by certain contract shippers, as well as contract terminations and restructurings. These volume decreases were partially offset by an increase in volume from incremental transportation volume from the Empire North project. Volume fluctuations, other than those caused by the addition or termination of contracts, generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.
The Pipeline and Storage segment’s earnings for the quarter ended December 31, 2020 were $24.2 million, an increase of $6.1 million when compared with earnings of $18.1 million for the quarter ended December 31, 2019. The increase in earnings was primarily due to the earnings impact of higher operating revenues of $12.3 million, as discussed above, partially offset by an increase in depreciation expense ($3.1 million), higher interest expense ($2.9 million) and a decrease in other income ($0.5 million). The increase in depreciation expense was primarily due to an increase in Supply Corporation's depreciation rates associated with its rate case settlement as well as incremental depreciation from the Empire North project going into service, both mentioned above. The increase in interest expense was primarily due to interest on additional intercompany long-term borrowings associated with the Company's June 2020 debt issuance. The decrease in other income was mainly due to a decrease in allowance for funds used during construction (equity component) as a result of the Empire North project being placed in service during the fourth quarter of fiscal 2020, partially offset by higher non-service pension and post-retirement benefit costs in the current quarter compared to non-service pension and post-retirement income in the prior year's quarter.
Gathering
Gathering Operating Revenues
Three Months Ended December 31,
(Thousands)
2020
2019
Increase (Decrease)
Gathering Revenues
$
47,009
$
34,788
$
12,221
Gathering Volume
Three Months Ended December 31,
2020
2019
Increase (Decrease)
Gathered Volume - (MMcf)
87,135
64,392
22,743
2020 Compared with 2019
Operating revenues for the Gathering segment increased $12.2 million for the quarter ended December 31, 2020 as compared with the quarter ended December 31, 2019, which was driven primarily by a 22.7 Bcf increase in gathered volume. The July 31, 2020 acquisition of midstream gathering assets from Shell was the primary driver of this increase as the Tioga gathering system (the name given to the acquired assets) recorded 20.5 Bcf of gathered volume for the quarter ended December 31, 2020. Other contributors to the increase included the Clermont gathering system, which experienced a 4.2 Bcf increase in gathered volume and the Wellsboro gathering system, which experienced a 0.9 Bcf increase in gathered volume. These increases were partially offset by a 1.8 Bcf decrease in gathered volume at the Trout Run gathering system and a 1.0 Bcf decrease in volume at the Covington gathering system. The net increase in gathered volume can be attributed primarily to the
increase in Seneca's gross natural gas production in the Appalachian region, which increased despite price-related curtailments initiated by Seneca, as discussed above.
The Gathering segment’s earnings for the quarter ended December 31, 2020 were $20.6 million, an increase of $4.7 million when compared with earnings of $15.9 million for the quarter ended December 31, 2019. The increase in earnings was primarily attributable to higher gathering revenues ($9.7 million) driven by the increase in gathered volume (discussed above). This earnings increase was partially offset by higher depreciation expense ($2.2 million), higher interest expense ($1.5 million) and higher operating expenses ($1.5 million), with each of these increases primarily being a result of the acquisition of midstream gathering assets from Shell on July 31, 2020. The increase in depreciation expense was largely due to a higher plant balance at the Covington gathering system. The increase in interest expense was primarily driven by additional intercompany long-term borrowings from the Company's long-term debt issuance in June 2020. The increase in operating expenses was largely due to higher lease compression expense associated with the Tioga gathering system.
Utility
Utility Operating Revenues
Three Months Ended December 31,
(Thousands)
2020
2019
Increase (Decrease)
Retail Sales Revenues:
Residential
$
140,844
$
145,615
$
(4,771)
Commercial
18,207
19,661
(1,454)
Industrial
931
1,267
(336)
159,982
166,543
(6,561)
Transportation
30,631
33,606
(2,975)
Other
(1,612)
(3,324)
1,712
$
189,001
$
196,825
$
(7,824)
Utility Throughput
Three Months Ended December 31,
(MMcf)
2020
2019
Increase (Decrease)
Retail Sales:
Residential
18,412
19,476
(1,064)
Commercial
2,528
2,812
(284)
Industrial
153
217
(64)
21,093
22,505
(1,412)
Transportation
17,935
20,556
(2,621)
39,028
43,061
(4,033)
Degree Days
Three Months Ended December 31,
Percent Colder (Warmer) Than
Normal
2020
2019
Normal(1)
Prior Year(1)
Buffalo, NY
2,253
1,921
2,232
(14.7)
%
(13.9)
%
Erie, PA
2,044
1,697
1,906
(17.0)
%
(11.0)
%
(1)Percents compare actual 2020 degree days to normal degree days and actual 2020 degree days to actual 2019 degree days.
Operating revenues for the Utility segment decreased $7.8 million for the quarter ended December 31, 2020 as compared with the quarter ended December 31, 2019. The decrease primarily resulted from a $6.6 million decrease in retail gas sales revenue and a $3.0 million decrease in transportation revenues. The reduction in retail gas sales revenue was largely due to a decrease in the cost of gas sold (per Mcf) coupled with lower throughput due to warmer weather. The decline in transportation revenues was primarily due to a 2.6 Bcf decrease in transportation throughput as residential customers switched from transportation service to retail service. These decreases were partially offset by a $1.7 million increase in other revenues. The increase in other revenues was largely due to a smaller estimated refund provision recorded during the quarter for the income tax benefits resulting from the 2017 Tax Reform Act ($1.3 million) that are required to be passed back to ratepayers.
The Utility segment’s earnings for the quarter ended December 31, 2020 were $23.0 million, a decrease of $3.6 million when compared with earnings of $26.6 million for the quarter ended December 31, 2019. The decrease in earnings was largely attributable to higher operating expenses ($2.0 million), which were a result of higher personnel costs and an increase to the allowance for uncollectible accounts, partially offset by lower legal and consultant fees. Higher income tax expense ($1.4 million) and the impact of lower usage and weather on customer margins ($1.2 million) also contributed to the decrease in earnings. The increase to the allowance for uncollectible accounts is related to the COVID-19 pandemic as the Company recorded incremental expense due to the potential for customer non-payment, given the current economic environment. These decreases were slightly offset by the positive earnings impact related to a system modernization tracker in New York ($0.9 million).
The impact of weather variations on earnings in the Utility segment's New York rate jurisdiction is mitigated by that jurisdiction's weather normalization clause (WNC). The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. In addition, in periods of colder than normal weather, the WNC benefits the Utility segment's New York customers. For the quarter ended December 31, 2020, the WNC increased earnings by approximately $1.6 million, as the weather was warmer than normal. For the quarter ended December 31, 2019, the WNC decreased earnings by approximately $0.1 million, as the weather was colder than normal.
Corporate and All Other
2020 Compared with 2019
Corporate and All Other operations had earnings of $39.6 million for the quarter ended December 31, 2020, an increase of $37.6 million when compared with earnings of $2.0 million for the quarter ended December 31, 2019. The increase in earnings was primarily attributable to the gain recognized on the sale of timber properties by Seneca's Northeast Division for $51.1 million ($37.0 million after-tax) as discussed in Item 1 at Note 2 – Asset Acquisitions and Divestitures.
Interest Expense on Long-Term Debt
Interest on long-term debt increased $6.8 million for the quarter ended December 31, 2020, as compared to the quarter ended December 31, 2019 due in large part to the issuance of $500.0 million of 5.50% notes on June 3, 2020.
CAPITAL RESOURCES AND LIQUIDITY
The Company’s primary sources of cash during the three-month period ended December 31, 2020 consisted of cash provided by operating activities and net proceeds from the sale of timber properties. The Company's primary sources of cash during the three-month period ended December 31, 2019 consisted of cash provided by operating activities and net proceeds from short-term borrowings.
Operating Cash Flow
Internally generated cash from operating activities consists of net income available for common stock, adjusted for non-cash expenses, non-cash income and changes in operating assets and liabilities. Non-cash items include depreciation, depletion and amortization, impairment of oil and gas producing properties, gain on sale of timber properties, deferred income taxes and stock-based compensation.
Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from period to period because of the impact of rate cases. In the Utility segment, supplier refunds, over- or under-recovered
purchased gas costs and weather may also significantly impact cash flow. The impact of weather on cash flow is tempered in the Utility segment’s New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by the straight fixed-variable rate design used by Supply Corporation and Empire.
Because of the seasonal nature of the heating business in the Utility segment, revenues in this business are relatively high during the heating season, primarily the first and second quarters of the fiscal year, and receivable balances historically increase during these periods from the receivable balances at September 30.
The storage gas inventory normally declines during the first and second quarters of the fiscal year and is replenished during the third and fourth quarters. For storage gas inventory accounted for under the LIFO method, 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 is reduced as the inventory is replenished.
Cash provided by operating activities in the Exploration and Production segment may vary from period to period as a result of changes in the commodity prices of natural gas and crude oil as well as changes in production. The Company uses various derivative financial instruments, including price swap agreements and no cost collars, in an attempt to manage this energy commodity price risk.
Net cash provided by operating activities totaled $204.7 million for the three months ended December 31, 2020, an increase of $37.0 million compared with $167.7 million provided by operating activities for the three months ended December 31, 2019. The increase in cash provided by operating activities primarily reflects higher cash provided by operating activities in the Pipeline and Storage segment, the Exploration and Production segment, and the Gathering segment. The increase in the Pipeline and Storage segment was primarily due to higher cash receipts from transportation and storage service, which largely reflects an increase in Supply Corporation's transportation and storage rates effective February 1, 2020 and an increase in demand charges for transportation services from the Empire North project that was placed in service during September 2020 and the Line N to Monaca Project that was placed in service in November 2019. The increase in the Exploration and Production segment and the Gathering segment was primarily due to higher cash receipts from natural gas production and gathering services in the Appalachian region, largely stemming from the July 31, 2020 acquisition of upstream assets and midstream gathering assets from Shell.
Investing Cash Flow
Expenditures for Long-Lived Assets
The Company’s expenditures for long-lived assets totaled $150.9 million during the three months ended December 31, 2020 and $211.2 million during the three months ended December 31, 2019. The table below presents these expenditures:
Total Expenditures for Long-Lived Assets
Three Months Ended December 31,
2020
2019
Increase (Decrease)
(Millions)
Exploration and Production:
Capital Expenditures
$
81.3
(1)
$
126.9
(2)
$
(45.6)
Pipeline and Storage:
Capital Expenditures
43.7
(1)
57.1
(2)
(13.4)
Gathering:
Capital Expenditures
8.3
(1)
9.8
(2)
(1.5)
Utility:
Capital Expenditures
17.3
(1)
17.2
(2)
0.1
All Other:
Capital Expenditures
0.1
0.2
(0.1)
Eliminations
0.2
—
0.2
$
150.9
$
211.2
$
(60.3)
(1)At December 31, 2020, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $35.1 million, $11.2 million, $2.3 million and $3.5 million, respectively, of non-cash capital expenditures. At September 30,
2020, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $45.8 million, $17.3 million, $13.5 million and $10.7 million, respectively, of non-cash capital expenditures.
(2)At December 31, 2019, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $62.3 million, $22.7 million, $5.3 million and $3.5 million, respectively, of non-cash capital expenditures. At September 30, 2019, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $38.0 million, $23.8 million, $6.6 million and $12.7 million, respectively, of non-cash capital expenditures.
Exploration and Production
The Exploration and Production segment capital expenditures for the three months ended December 31, 2020 were primarily well drilling and completion expenditures and included approximately $79.9 million for the Appalachian region (including $30.5 million in the Marcellus Shale area and $43.9 million in the Utica Shale area) and $1.4 million for the West Coast region. These amounts included approximately $34.3 million spent to develop proved undeveloped reserves.
The Exploration and Production segment capital expenditures for the three months ended December 31, 2019 were primarily well drilling and completion expenditures and included approximately $119.0 million for the Appalachian region (including $53.7 million in the Marcellus Shale area and $63.8 million in the Utica Shale area) and $7.9 million for the West Coast region. These amounts included approximately $86.2 million spent to develop proved undeveloped reserves.
Pipeline and Storage
The Pipeline and Storage segment capital expenditures for the three months ended December 31, 2020 were primarily for expenditures related to Supply Corporation's FM100 Project ($30.4 million), which is discussed below. In addition, the Pipeline and Storage segment capital expenditures for the three months ended December 31, 2020 included additions, improvements and replacements to this segment’s transmission and gas storage systems. The Pipeline and Storage segment capital expenditures for the three months ended December 31, 2019 were primarily for expenditures related to the Empire North Project ($29.1 million) and Supply Corporation's Line N to Monaca Project ($3.3 million). In addition, the Pipeline and Storage segment capital expenditures for the three months ended December 31, 2019 included additions, improvements and replacements to this segment’s transmission and gas storage systems.
In light of the continuing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia, specifically in the Marcellus and Utica Shale producing areas, Supply Corporation and Empire have completed and continue to pursue expansion projects designed to move anticipated Marcellus and Utica production gas to other interstate pipelines and to on-system markets, and markets beyond the Supply Corporation and Empire pipeline systems. Preliminary survey and investigation costs for expansion, routine replacement or modernization projects are initially recorded as Deferred Charges on the Consolidated Balance Sheet. Management may reserve for preliminary survey and investigation costs associated with large projects by reducing the Deferred Charges balance and increasing Operation and Maintenance Expense on the Consolidated Statement of Income. If it is determined that it is highly probable that a project for which a reserve has been established will be built, the reserve is reversed. This reversal reduces Operation and Maintenance Expense and reestablishes the original balance in Deferred Charges. The amounts remain in Deferred Charges until such time as capital expenditures for the project have been incurred and activities that are necessary to get the construction project ready for its intended use are in progress. At that point, the balance is transferred from Deferred Charges to Construction Work in Progress, a component of Property, Plant and Equipment on the Consolidated Balance Sheet.
Supply Corporation has developed its FM100 Project, which will upgrade a 1950's era pipeline in northwestern Pennsylvania and create approximately 330,000 Dth per day of additional transportation capacity in Pennsylvania from a receipt point with NFG Midstream Clermont, LLC in McKean County to the Transcontinental Gas Pipe Line Company, LLC (“Transco”) system at Leidy, Pennsylvania. A precedent agreement has been executed by Supply Corporation and Transco whereby this additional capacity is expected to be leased by Transco and become part of a Transco expansion project ("Leidy South") that will create incremental transportation capacity to Transco Zone 6 markets. Seneca is an anchor shipper on Leidy South, which provides it with an outlet to premium markets from both its Eastern and Western development areas. FERC issued the Section 7(c) certificate on July 17, 2020 and Supply Corporation accepted it on August 14, 2020. The FM100 Project has a target in-service date of late calendar 2021 and a preliminary cost estimate of approximately $280 million. As of December 31, 2020, approximately $34.3 million has been capitalized as Construction Work in Progress for this project.
Supply Corporation and Empire have developed a project which would move significant prospective Marcellus production from Seneca's Western Development Area at Clermont to an Empire interconnection with the TC Energy pipeline at Chippawa and an interconnection with TGP's 200 Line in East Aurora, New York (the “Northern Access project”). The Northern Access project would provide an outlet to Dawn-indexed markets in Canada and to the TGP line serving the U.S.
Northeast. The Northern Access project involves the construction of approximately 99 miles of largely 24” pipeline and approximately 27,500 horsepower of compression on the two systems. Supply Corporation, Empire and Seneca executed anchor shipper agreements for 350,000 Dth per day of firm transportation delivery capacity to Chippawa and 140,000 Dth per day of firm transportation capacity to a new interconnection with TGP's 200 Line on this project. On February 3, 2017, the Company received FERC approval of the project. Shortly thereafter, 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 in January of 2017). The United States Court of Appeals for the Second Circuit (the “Second Circuit Court of Appeals”) held in the Company’s favor in its appeal of this decision, vacating the NYDEC denial and remanding to the NYDEC. The NYDEC subsequently issued a second denial, which the Company has appealed to the Second Circuit Court of Appeals. The court has held this appeal in abeyance pending the outcome of the FERC waiver appeal, described below. While the Company’s initial appeal was pending before the Second Circuit Court of Appeals, 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. FERC denied rehearing requests associated with its Order, and FERC's decisions have been appealed and are pending in a separate action before the Second Circuit Court of Appeals. In addition, in the Company's state court litigation challenging the NYDEC's actions with regard to various state permits, the New York State Supreme Court issued a decision finding these permits to be preempted. The Company remains committed to the project. The Company will update the $500 million preliminary cost estimate and expected in-service date for the project when there is further clarity on the pending legal actions. As of December 31, 2020, approximately $58.7 million has been spent on the Northern Access project, including $24.0 million that has been spent to study the project, for which no reserve has been established. The remaining $34.7 million spent on the project has been capitalized as Construction Work in Progress.
Gathering
The majority of the Gathering segment capital expenditures for the three months ended December 31, 2020 included expenditures related to the continued expansion of Midstream Company's Clermont and Wellsboro gathering systems, as discussed below. Midstream Company spent $4.5 million and $3.1 million, respectively, during the three months ended December 31, 2020 on the development of the Clermont and Wellsboro gathering systems. These expenditures were largely attributable to the continued development of centralized station facilities, including increased compression horsepower at the Clermont and Wellsboro gathering systems and additional dehydration on the Clermont gathering system.
The majority of the Gathering segment capital expenditures for the three months ended December 31, 2019 were for the continued expansion of Midstream Company's Trout Run, Clermont and Wellsboro gathering systems. Midstream Company spent $5.5 million, $3.2 million and $1.1 million, respectively, during the three months ended December 31, 2019 on the development of the Trout Run, Clermont and Wellsboro gathering systems. These expenditures were largely attributable to new gathering pipelines and the continued development of centralized station facilities, including increased compression horsepower at the Trout Run gathering system.
NFG Midstream Clermont, LLC, a wholly owned subsidiary of Midstream Company, continues to develop an extensive gathering system with compression in the Pennsylvania counties of McKean, Elk and Cameron. The Clermont gathering system was initially placed in service in July 2014. The current system consists of three compressor stations and backbone and in-field gathering pipelines. The total cost estimate for the continued buildout will be dependent on the nature and timing of Seneca's long-term plans.
NFG Midstream Wellsboro, LLC, a wholly owned subsidiary of Midstream Company, continues to develop its Wellsboro gathering system in Tioga County, Pennsylvania. The current system consists of one compressor station and backbone and in-field gathering pipelines.
NFG Midstream Trout Run, LLC, a wholly owned subsidiary of Midstream Company, continues to develop its Trout Run gathering system in Lycoming County, Pennsylvania. The Trout Run gathering system was initially placed in service in May 2012. The current system consists of three compressor stations and backbone and in-field gathering pipelines.
Utility
The majority of the Utility segment capital expenditures for the three months ended December 31, 2020 and December 31, 2019 were made for main and service line improvements and replacements that enhance the reliability and safety of the system and reduce emissions. Expenditures were also made for main extensions.
On December 10, 2020, the Company completed the sale of substantially all timber properties in Pennsylvania to Lyme Emporium Highlands III LLC and Lyme Allegheny Land Company II LLC for net proceeds of $104.6 million. After purchase price adjustments and transaction costs, a gain of $51.1 million was recognized on the sale of these assets ($37.0 million after-tax). The sale of the timber properties completed a reverse like-kind exchange pursuant to Section 1031 of the Internal Revenue Code, as amended (“Reverse 1031 Exchange”). On July 31, 2020, the Company completed its acquisition of certain upstream assets and midstream gathering assets in Pennsylvania from Shell for total consideration of $506.3 million. The purchase and sale agreement with Shell was structured, in part, as a Reverse 1031 Exchange. Refer to Item 8, Note B – Asset Acquisitions and Divestitures, of the Company’s 2020 Form 10-K for additional information concerning the Company’s acquisition of certain upstream assets and midstream gathering assets from Shell.
Project Funding
Over the past two years, the Company has been financing capital expenditures with cash from operations, short-term and long-term debt, common stock, and proceeds from the sale of timber properties. During the quarters ended December 31, 2020 and December 31, 2019, capital expenditures were funded with cash from operations and short-term debt. The Company issued long-term debt and common stock in June 2020 to help finance the acquisition of upstream assets and midstream gathering assets from Shell. The financing of the asset acquisition from Shell was completed in December 2020 when the Company completed the sale of substantially all of its timber properties, through the completion of the Reverse 1031 Exchange discussed above. Going forward, the Company expects to use cash on hand, cash from operations and short-term borrowings to finance capital expenditures. The level of short-term borrowings will depend upon the amount of cash provided by operations, which, in turn, will likely be impacted by natural gas and crude oil prices combined with production from existing wells. As disclosed above, the Company is precluded from issuing incremental long-term debt beginning in January 2021 as a means of financing these projects. The Company expects this restriction to extend into the second half of fiscal 2021.
The Company continuously evaluates capital expenditures and potential investments in corporations, partnerships, and other business entities. The amounts are subject to modification for opportunities such as the acquisition of attractive oil and gas properties, natural gas storage facilities, natural gas gathering and compression facilities and the expansion of natural gas transmission line capacities, regulated utility assets and other opportunities as they may arise. While the majority of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company’s other business segments depends, to a large degree, upon market and regulatory conditions.
Financing Cash Flow
Consolidated short-term debt decreased $5.0 million when comparing the balance sheet at December 31, 2020 to the balance sheet at September 30, 2020. The maximum amount of short-term debt outstanding during the quarter ended December 31, 2020 was $145.8 million. The Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, exploration and development expenditures, other working capital needs and repayment of long-term debt. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. At December 31, 2020, the Company had outstanding commercial paper of $25.0 million. The Company did not have any outstanding short-term notes payable to banks at December 31, 2020.
The Company maintains $1.0 billion of unsecured committed revolving credit access across two facilities. On October 25, 2018, the Company entered into a Fourth Amended and Restated Credit Agreement ("Credit Agreement") with a syndicate of twelve banks. This Credit Agreement provides a $750.0 million multi-year unsecured committed revolving credit facility through October 25, 2023. In addition to the Credit Agreement, on February 3, 2021, the Company amended its existing 364-Day Credit Agreement to extend the maturity date thereof from May 3, 2021 to December 30, 2022, and to increase the lenders' commitments thereunder from $200.0 million to $250.0 million, among other changes (as amended, the "Amended 364-Day Credit Agreement"). Twelve banks are parties to the Amended 364-Day Credit Agreement, all of which are also lenders under the Credit Agreement. The Company also has uncommitted lines of credit with financial institutions for general corporate purposes. Borrowings under these uncommitted lines of credit would be made at competitive market rates. The uncommitted credit lines are revocable at the option of the financial institution and are reviewed on an annual basis. The Company anticipates that its uncommitted lines of credit generally will be renewed or substantially replaced by similar lines. Other financial institutions may also provide the Company with uncommitted or discretionary lines of credit in the future.
The total amount available to be issued under the Company’s commercial paper program is $500.0 million. The commercial paper program is backed by the Credit Agreement, which provides that the Company's debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter. For purposes of calculating the debt to capitalization ratio, the Company's total capitalization will be increased by adding back 50% of the aggregate after-tax amount of non-cash charges directly arising from any ceiling test impairment occurring on or after July 1, 2018, not to exceed $250 million. This provision also applies to the Amended 364-Day Credit Agreement. Since July 1, 2018, the Company recorded non-cash, after-tax ceiling test impairments totaling $381.4 million. As a result, at December 31, 2020, $190.7 million was added back to the Company's total capitalization for purposes of the facility, and the Company’s debt to capitalization ratio, as calculated under the facility, was .54. The constraints specified in both the Credit Agreement and Amended 364-Day Credit Agreement would have permitted an additional $1.49 billion in short-term and/or long-term debt to be outstanding at December 31, 2020 (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio exceeded .65.
A downgrade in the Company’s credit ratings could increase borrowing costs, negatively impact the availability of capital from banks, commercial paper purchasers and other sources, and require the Company's subsidiaries to post letters of credit, cash or other assets as collateral with certain counterparties. If the Company is not able to maintain investment-grade credit ratings, it may not be able to access commercial paper markets. However, the Company expects that it could borrow under its credit facilities or rely upon other liquidity sources.
The Credit Agreement and Amended 364-Day Credit Agreement contain a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement and the Amended 364-Day Credit Agreement. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $40.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity.
The Current Portion of Long-Term Debt at December 31, 2020 consists of $500.0 million aggregate principal amount of 4.90% notes that mature in December 2021. None of the Company's long-term debt as of September 30, 2020 had a maturity date within the following twelve-month period.
The Company’s embedded cost of long-term debt was 4.85% and 4.69% at December 31, 2020 and December 31, 2019, respectively.
The Company's present liquidity position is believed to be adequate to satisfy known demands. Under the Company’s existing indenture covenants at December 31, 2020, the Company is precluded from issuing incremental unsubordinated long-term indebtedness beginning in January 2021 as a result of non-cash impairments of its oil and gas properties recognized during fiscal 2020 and the quarter ended December 31, 2020, as discussed above. The Company expects this restriction to extend into the second half of fiscal 2021. The covenants would not preclude the Company from issuing long-term debt to refund existing long-term debt. In this regard, the Company plans to issue long-term debt during fiscal 2021 to refund its 4.90% notes, in the principal amount of $500 million, that are scheduled to mature in December 2021. Please refer to the Critical Accounting Estimates section above for a sensitivity analysis concerning commodity price changes and their impact on the ceiling test.
The Company’s 1974 indenture pursuant to which $99.0 million (or 3.7%) of the Company’s long-term debt (as of December 31, 2020) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.
OTHER MATTERS
In addition to the legal proceedings disclosed in Part II, Item 1 of this report, 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 or 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 normal-course matters could have a material effect on earnings and cash flows in
the period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.
During the three months ended December 31, 2020, the Company contributed $5.2 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 2021, the Company expects its contributions to the Retirement Plan to be in the range of $10.0 million to $20.0 million. In the remainder of 2021, the Company expects its contributions to its VEBA trusts to be in the range of $2.0 million to $2.5 million.
The Company, in its Exploration and Production segment, has extended the term of a contractual obligation related to hydraulic fracturing during the quarter ended December 31, 2020. This extension is valued at approximately $82.3 million and extends the contractual obligation through December 31, 2022.
Market Risk Sensitive Instruments
On July 21, 2010, the Dodd-Frank Act was signed into law. The Dodd-Frank Act includes provisions related to the swaps and over-the-counter derivatives markets that are designed to promote transparency, mitigate systemic risk and protect against market abuse. Although regulators have issued certain regulations, other rules that may impact the Company have yet to be finalized.
The CFTC’s Dodd-Frank regulations continue to preserve the ability of non-financial end users to hedge their risks using swaps without being subject to mandatory clearing. In 2015, legislation was enacted to exempt from margin requirements swaps used by non-financial end users to hedge or mitigate commercial risk. In 2016, the CFTC issued a reproposal to its position limit rules that would impose speculative position limits on positions in 28 core physical commodity contracts as well as economically equivalent futures, options and swaps. While the Company does not intend to enter into positions on a speculative basis, such rules could nevertheless impact the ability of the Company to enter into certain derivative hedging transactions with respect to such commodities. If the Company reduces its use of hedging transactions as a result of final regulations to be issued by the CFTC, results of operations may become more volatile and cash flows may be less predictable. There may be other rules developed by the CFTC and other regulators that could impact the Company. While many of those rules place specific conditions on the operations of swap dealers and major swap participants, concern remains that swap dealers and major swap participants will pass along their increased costs stemming from final rules through higher transaction costs and prices or other direct or indirect costs.
Finally, given the additional authority granted to the CFTC on anti-market manipulation, anti-fraud and disruptive trading practices, it is difficult to predict how the evolving enforcement priorities of the CFTC will impact our business. Should the Company violate any laws or regulations applicable to our hedging activities, it could be subject to CFTC enforcement action and material penalties and sanctions. The Company continues to monitor these enforcement and other regulatory developments, but cannot predict the impact that evolving application of the Dodd-Frank Act may have on its operations.
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, 2020, 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 a complete discussion of all other market risk sensitive instruments used by the Company, refer to “Market Risk Sensitive Instruments” in Item 7 of the Company’s 2020 Form 10-K.
Rate Matters
Utility Operation
Delivery rates for both the New York and Pennsylvania divisions are regulated by the states’ respective public utility commissions and typically are changed only when approved through a procedure known as a “rate case.” Neither the New York or Pennsylvania divisions currently have a rate case on file. In both jurisdictions, delivery rates do not reflect the recovery of
purchased gas costs. Prudently-incurred gas costs are recovered through operation of automatic adjustment clauses, and are collected primarily through a separately-stated “supply charge” on the customer bill.
New YorkJurisdiction
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 directed the implementation of an earnings sharing mechanism to be in place beginning on April 1, 2018.
In New York, on March 13, 2020, in response to the COVID-19 pandemic, the Company agreed to NYPSC Staff’s request that the Company suspend service terminations and disconnections. Thereafter, on June 17, 2020, New York enacted a new law that prohibits utilities from terminating or disconnecting services to any residential customer for non-payment for the duration of the state disaster emergency. In addition, the law prohibits residential terminations for non-payment for a period of 180 days running from the end of the state disaster emergency for customers that have experienced a change in financial circumstances due to the COVID-19 state of emergency. Governor Cuomo, through the issuance of executive orders, has extended the declaration of the state disaster emergency through February 26, 2021. The law currently sunsets on March 31, 2021, but legislation extending the moratorium is anticipated. The duration of the aforementioned suspension in New York and its related impact on the Company is uncertain. The Company is anticipating that customer non-payment may increase given higher natural gas usage and the resulting increase in costs for customers. It is uncertain at this point as to whether there would be any regulatory relief for utilities with regard to an increase in costs associated with the COVID-19 pandemic, but it is one of many issues currently being considered in a generic NYPSC proceeding entitled “Proceeding on Motion of the Commission Regarding the Effects of COVID-19 on Utility Service” (Case No. 20-M-0266). Correspondence from NYPSC Staff has recommended that utilities rely on existing avenues of relief for these costs, and has identified additional, more stringent requirements that must be met to achieve relief.
Pennsylvania Jurisdiction
Distribution Corporation’s current delivery rates in its Pennsylvania jurisdiction were approved by the PaPUC on November 30, 2006 as part of a settlement agreement that became effective January 1, 2007. The rate settlement does not specify any requirement to file a future rate case.
On March 26, 2020, the PaPUC ratified an Emergency Order that established a Service Termination Moratorium intended to continue during the pendency of Governor Wolf’s March 6, 2020 Proclamation of Disaster Emergency associated with the COVID-19 pandemic. On May 13, 2020, the Company (and other Pennsylvania local distribution companies) received a Secretarial Letter from the PaPUC regarding COVID-19 pandemic cost tracking and regulatory assets. The Secretarial Letter directs utilities to track “extraordinary, nonrecurring incremental COVID-19 related expenses” so the Commission can understand the impact of these expenses on the utilities’ finances. It also authorizes the creation of a utility regulatory asset, but only for incremental uncollectible expenses incurred above those embedded in rates (and incurred since the issuance of the Emergency Order). The Company currently does not anticipate a need to create a regulatory asset for these expenses. On October 8, 2020, the Commission issued an order ending the moratorium effective November 9, 2020, imposing a list of enhanced customer protections that expire on March 31, 2021 and calling for comments by February 16, 2021 regarding policies the Commission should adopt after March 31, 2021. The order also appears to expand the aforementioned potential utility regulatory asset to all incremental COVID-19 related expenses incurred above those embedded in rates. The Company continues to monitor this item for potential deferral opportunity.
Pipeline and Storage
Supply Corporation’s rate settlement, approved June 1, 2020, provides that no party may make a rate filing for new rates to be effective before February 1, 2024, except that Supply Corporation may file an NGA general Section 4 rate case to change rates if the corporate federal income tax rate is increased. If no case has been filed, Supply Corporation must file for rates to be effective February 1, 2025. Supply has no rate case currently on file.
Empire’s 2019 rate settlement provides that no party may make a filing for new rates before March 31, 2021. If no rate case has been filed, Empire must make a rate case filing no later than May 1, 2025.
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 comply with regulatory requirements.
For further discussion of the Company's environmental exposures, refer to Item 1 at Note 8 — Commitments and Contingencies under the heading “Environmental Matters.”
Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation in the United States. These efforts include legislation, legislative proposals and new regulations at the state and federal level, and private party litigation related to greenhouse gas emissions. The U.S. Congress has not yet passed any federal climate change legislation and we cannot predict when or if Congress will pass such legislation and in what form. In the absence of such legislation, the EPA regulates greenhouse gas emissions pursuant to the Clean Air Act. The regulations implemented by EPA impose more stringent leak detection and repair requirements, and further address reporting and control of methane and volatile organic compound emissions. The Company must continue to comply with all applicable regulations. A number of states have adopted energy strategies or plans with aggressive goals for the reduction of greenhouse gas emissions. Pennsylvania has a methane reduction framework with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines and is in the process of evaluating cap-and-trade programs (e.g., Regional Greenhouse Gas Initiative). In California, the Company currently complies with California cap-and-trade rules, which increases the Company's cost of environmental compliance in its Exploration and Production segment. Legislation or regulation that aims to reduce greenhouse gas emissions could also include emissions limits, reporting requirements, carbon taxes, restrictive permitting, increased efficiency standards, and incentives or mandates to conserve energy or use renewable energy sources. Federal, state or local governments may provide tax advantages and other subsidies to support alternative energy sources, mandate the use of specific fuels or technologies, or promote research into new technologies to reduce the cost and increase the scalability of alternative energy sources. The NYPSC, for example, initiated a proceeding to consider climate-related financial disclosures at the utility operating company level, and the NY State legislature passed the CLCPA that mandates reducing greenhouse gas emissions to 60% of 1990 levels by 2030, and to 15% of 1990 levels by 2050, with the remaining emission reduction achieved by controlled offsets. The CLCPA also requires electric generators to meet 70% of demand with renewable energy by 2030 and 100% with zero emissions generation by 2040. These climate change and greenhouse gas initiatives could impact the Company's customer base and assets depending on the promulgation of final regulations and on regulatory treatment afforded in the process. Thus far, the only regulations promulgated in connection with the CLCPA are greenhouse gas emissions limits established by the NYDEC in 6 NYCRR Part 496, effective December 30, 2020. The NYDEC has until January 1, 2024 to issue further rules and regulations implementing the statute. The above-enumerated initiatives could also increase the Company’s cost of environmental compliance by increasing reporting requirements, requiring retrofitting of existing equipment, requiring installation of new equipment, and/or requiring the purchase of emission allowances. They could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals. Changing market conditions and new regulatory requirements, as well as unanticipated or inconsistent application of existing laws and regulations by administrative agencies, make it difficult to predict a long-term business impact across twenty or more years.
Safe Harbor for Forward-Looking Statements
The Company is including the following cautionary statement in this Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Certain statements contained in this report, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis,
but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements:
1.The length and severity of the recent COVID-19 pandemic, including its impacts across our businesses on demand, operations, global supply chains and liquidity;
2.Changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services;
3.Changes in the price of natural gas or oil;
4.Impairments under the SEC’s full cost ceiling test for natural gas and oil reserves;
5.The creditworthiness or performance of the Company’s key suppliers, customers and counterparties;
6.Financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions;
7.Changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing;
8.Delays or changes in costs or plans with respect to Company projects or related projects of other companies, including disruptions due to the COVID-19 pandemic, as well as difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators;
9.The Company's ability to complete planned strategic transactions;
10.The Company's ability to successfully integrate acquired assets and achieve expected cost synergies;
11.Governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, target rates of return, rate design and retained natural gas), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal;
12.Changes in price differentials between similar quantities of natural gas or oil at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations;
13.The impact of information technology disruptions, cybersecurity or data security breaches;
14.Factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including among others geology, lease availability, title disputes, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations;
15.Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits;
16.Other changes in price differentials between similar quantities of natural gas or oil having different quality, heating value, hydrocarbon mix or delivery date;
17.The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company;
18.Uncertainty of oil and gas reserve estimates;
19.Significant differences between the Company’s projected and actual production levels for natural gas or oil;
20.Changes in demographic patterns and weather conditions;
21.Changes in the availability, price or accounting treatment of derivative financial instruments;
22.Changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities;
23.Economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities or acts of war;
24.Significant differences between the Company’s projected and actual capital expenditures and operating expenses; or
25.Increasing costs of insurance, changes in coverage and the ability to obtain insurance.
The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Refer to the "Market Risk Sensitive Instruments" section in Item 2 – MD&A.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, including the Chief Executive Officer and Principal Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the Company’s Chief Executive Officer and Principal Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2020.
Changes in Internal Control Over Financial Reporting
There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended December 31, 2020 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Part II. Other Information
Item 1. Legal Proceedings
For a discussion of various environmental and other matters, refer to Part I, Item 1 at Note 8 – Commitments and Contingencies, and Part I, Item 2 - MD&A of this report under the heading “Other Matters – Environmental Matters.”
For a discussion of certain rate matters involving the NYPSC, refer to Part I, Item 1 of this report at Note 11 – Regulatory Matters.
Item 1A. Risk Factors
The risk factors in Item 1A of the Company’s 2020 Form 10-K have not materially changed other than as set forth below. The risk factors presented below supersede the risk factors having the same caption in the 2020 Form 10-K and should otherwise be read in conjunction with all of the risk factors disclosed in the 2020 Form 10-K. The impact of the COVID-19 pandemic may also exacerbate other risks discussed in Item 1A of the Company’s 2020 Form 10-K, any of which could have a material effect on us. This situation is changing rapidly and additional impacts may arise that we are not aware of currently.
Climate change, and the regulatory, legislative and capital access developments related to climate change, may adversely affect operations and financial results.
Climate change could create physical risks, which may adversely affect the Company’s operations. Physical risks include changes in weather conditions, which could cause demand for gas to increase or decrease. If there were to be any impacts from climate change to the Company’s operations and financial results, the Company expects that they would likely
occur over a long period of time and thus are difficult to quantify with any degree of specificity. Extreme weather events may result in adverse physical effects on portions of the country’s gas infrastructure, which could disrupt the Company’s supply chain and ultimately its operations. Disruption of production activities, and transportation and distribution systems could result in reduced operational efficiency, and customer service interruption.
Climate change, and the laws, regulations and other initiatives to address climate change, may impact the Company’s financial results. On January 20, 2021, the federal administration executed the instrument stating the country's intent to rejoin the Paris Agreement, the international effort to establish emissions reduction goals for signatory countries, thus allowing for the U.S. to reenter the Paris Agreement as an official party thirty days later. Under the Paris Agreement, signatory countries are expected to submit their nationally determined contributions to curb greenhouse gas emissions and meet the agreed temperature objectives every five years. In addition to the recent federal intent to reenter the Paris Agreement, state and local governments, non-governmental organizations, and financial institutions have made, and will likely continue to make, more aggressive efforts to reduce emissions and advance the objectives of the Paris Agreement. Recent executive orders from the new federal administration, in addition to federal, state and local legislative and regulatory initiatives proposed or adopted in an attempt to limit the effects of climate change, including greenhouse gas emissions, could have significant impacts on the energy industry including government-imposed limitations, prohibitions or moratoriums on the use and development and production of gas and oil, establishment of a carbon tax, as well as accelerated depreciation of assets and/or stranded assets. For example, the U.S. Congress has from time to time considered bills that would establish a cap-and-trade program to reduce emissions of greenhouse gases. A number of states have adopted energy strategies or plans with goals that include the reduction of greenhouse gas emissions. For example, Pennsylvania has a methane reduction framework for the oil and gas industry which has resulted in permitting changes with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines. With respect to its operations in California, the Company currently complies with California cap-and-trade guidelines, which increases the Company’s cost of environmental compliance in its Exploration and Production segment operation. In addition, the NYPSC initiated a proceeding to consider climate-related financial disclosures at the utility operating level, and the NY State legislature passed the CLCPA, which created emission reduction and electric generation mandates, and could ultimately impact the Utility segment’s customer base and the Utility segment’s business. Legislation or regulation that aims to reduce greenhouse gas emissions could also include greenhouse gas emissions limits and reporting requirements, carbon taxes, restrictive permitting, increased efficiency standards, and incentives or mandates to conserve energy or use renewable energy sources. Additionally, the trend toward increased conservation, competition from renewable energy sources, and technological advances to address climate change may reduce the demand for natural gas. For further discussion of the risks associated with environmental regulation to address climate change, refer to Item 7, MD&A under the heading “Environmental Matters” and subheading “Environmental Regulation.”
Further, recent trends directed toward a low-carbon economy could shift funding away from, or limit or restrict certain sources of funding for, companies focused on fossil fuel-related development or carbon-intensive investments. To the extent financial markets view climate change and greenhouse gas emissions as a financial risk, the Company’s cost of and access to capital could be negatively impacted.
The Company may be adversely affected by economic conditions and their impact on our suppliers and customers.
Periods of slowed economic activity generally result in decreased energy consumption, particularly by industrial and large commercial companies. As a consequence, national or regional recessions or other downturns in economic activity, including the effects of the COVID-19 pandemic, could adversely affect the Company’s revenues and cash flows or restrict its future growth. The Company is monitoring and responding to the impacts of the COVID-19 pandemic across its businesses. To date, the COVID-19 pandemic has not had a material impact on the Company. However, the Company cannot predict the extent or duration of the outbreak or whether this rapidly evolving situation will have a material impact on the Company’s workforce, supply chain, operations or financial results, including potential regulatory responses to the financial impacts associated with the COVID-19 pandemic on the Company and its customers. Economic conditions in the Company’s utility service territories, along with legislative and regulatory prohibitions and/or limitations on terminations of service, also impact its collections of accounts receivable. For instance, New York enacted legislation that prohibits residential utility terminations for non-payment for the duration of the New York State COVID Disaster Emergency. All of the Company’s segments are exposed to risks associated with the creditworthiness or performance of key suppliers and customers, many of which may be adversely affected by volatile conditions in the financial markets, including volatility caused by the ongoing COVID-19 pandemic. These conditions could result in financial instability or other adverse effects at any of our suppliers or customers. For example, counterparties to the Company’s commodity hedging arrangements or commodity sales contracts might not be able to perform their obligations under these arrangements or contracts. Customers of the Company’s Utility segment may have particular trouble paying their bills during periods of declining economic activity or high commodity prices, potentially resulting in increased bad debt expense and reduced earnings; the PaPUC has directed utilities to track extraordinary, nonrecurring incremental COVID-19 related expenses, and has authorized the creation of a utility regulatory asset but only for incremental
COVID-19 related expenses incurred above those embedded in rates, therefore it is unclear at this time to what extent the PaPUC will, and whether the NYPSC will at all, allow rate recovery for COVID-19 pandemic related expenses. Similarly, if reductions were to occur in funding of the federal Low Income Home Energy Assistance Program, bad debt expense could increase and earnings could decrease. In addition, oil and gas exploration and production companies that are customers of the Company’s Pipeline and Storage segment may decide not to renew contracts for the same transportation capacity during periods of reduced production due to persistent low commodity prices. Any of these events could have a material adverse effect on the Company’s results of operations, financial condition and cash flows.
Financial accounting requirements regarding exploration and production activities may affect the Company's profitability.
The Company accounts for its exploration and production activities under the full cost method of accounting. Each quarter, the Company must perform a "ceiling test" calculation, comparing the level of its unamortized investment in oil and gas properties to the present value of the future net revenue projected to be recovered from those properties according to methods prescribed by the SEC. In determining present value, the Company uses a 12-month historical average price for oil and gas (based on first day of the month prices and adjusted for hedging) as well as the SEC mandated discount rate. If, at the end of any quarter, the amount of the unamortized investment exceeds the net present value of the projected future cash flows, such investment may be considered to be "impaired," and the full cost accounting rules require that the investment must be written down to the calculated net present value. Such an instance would require the Company to recognize an immediate expense in that quarter, and its earnings would be reduced. Depending on the magnitude of any decrease in average prices, that charge could be material. Under the Company's existing indenture covenants, an impairment could restrict the Company's ability to issue incremental long-term unsecured indebtedness for a period of time, beginning with the fourth calendar month following the impairment. For the fiscal year ended September 30, 2020 and the quarter ended December 31, 2020, the Company recognized non-cash, pre-tax impairment charges on its oil and natural gas properties of $449.4 million and $76.2 million, respectively, and the Company is precluded from issuing incremental unsubordinated long-term indebtedness for a period beginning in January 2021 and expected to extend into the second half of fiscal 2021.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
On October 1, 2020, the Company issued a total of 10,880 unregistered shares of Company common stock to ten non-employee directors of the Company then serving on the Board of Directors of the Company, consisting of 1,088 shares to each such director. All of these unregistered shares were issued under the Company’s 2009 Non-Employee Director Equity Compensation Plan as partial consideration for such directors’ services during the quarter ended December 31, 2020. These transactions were exempt from registration under Section 4(a)(2) of the Securities Act of 1933, as transactions not involving a public offering.
Issuer Purchases of Equity Securities
Period
Total Number of Shares Purchased (a)
Average Price Paid per Share
Total Number of Shares Purchased as Part of Publicly Announced Share Repurchase Plans or Programs
Maximum Number of Shares That May Yet Be Purchased Under Share Repurchase Plans or Programs (b)
Oct. 1 - 31, 2020
13,724
$41.26
—
6,971,019
Nov. 1 - 30, 2020
18,919
$41.18
—
6,971,019
Dec. 1 - 31, 2020
91,113
$42.71
—
6,971,019
Total
123,756
$42.31
—
6,971,019
(a)Represents (i) shares of common stock of the Company purchased with Company “matching contributions” for the accounts of participants in the Company’s 401(k) plans, and (ii) shares of common stock of the Company tendered to the Company by holders of stock-based compensation awards for the payment of applicable withholding taxes. During the quarter ended December 31, 2020, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase program. Of the 123,756 shares purchased other than through a publicly announced share repurchase program, 40,969 were purchased for the Company's 401(k) plans and 82,787 were purchased as a result of shares tendered to the Company by holders of stock-based compensation awards.
(b)In September 2008, the Company’s Board of Directors authorized the repurchase of eight million shares of the Company’s common stock. The repurchase program has no expiration date. The Company has not repurchased any shares since September 17, 2008 and has no plans to make further purchases in the near future.
Interactive data files submitted pursuant to Regulation S-T, formatted in Inline XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income and Earnings Reinvested in the Business for the three months ended December 31, 2020 and 2019, (ii) the Consolidated Statements of Comprehensive Income for the three months ended December 31, 2020 and 2019, (iii) the Consolidated Balance Sheets at December 31, 2020 and September 30, 2020, (iv) the Consolidated Statements of Cash Flows for the three months ended December 31, 2020 and 2019 and (v) the Notes to Condensed Consolidated Financial Statements.
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Cover Page Interactive Data File (embedded within the Inline XBRL document)
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Incorporated herein by reference as indicated.
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In accordance with Item 601(b)(32)(ii) of Regulation S-K and SEC Release Nos. 33-8238 and 34-47986, Final Rule: Management’s Reports on Internal Control Over Financial Reporting and Certification of Disclosure in Exchange Act Periodic Reports, the material contained in Exhibit 32 is “furnished” and not deemed “filed” with the SEC and is not to be incorporated by reference into any filing of the Registrant under the Securities Act of 1933 or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language contained in such filing, except to the extent that the Registrant specifically incorporates it by reference.
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
