☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended December 31, 2021
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, 2022: 91,443,921 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.
OPEB
Other Post-Employment Benefit
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, 2021, 2020 and 2019 that are included in the Company's 2021 Form 10-K. The consolidated financial statements for the year ended September 30, 2022 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, 2021 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2022. 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, 2021
Three Months Ended December 31, 2020
Balance at October 1, 2021
Balance at December 31, 2021
Balance at October 1, 2020
Balance at December 31, 2020
Cash and Temporary Cash Investments
$
31,528
$
79,065
$
20,541
$
109,413
Hedging Collateral Deposits
88,610
—
—
—
Cash, Cash Equivalents, and Restricted Cash
$
120,138
$
79,065
$
20,541
$
109,413
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.
Activity in the allowance for uncollectible accounts for the three months ended December 31, 2021 and 2020 are as follows (in thousands):
Balance at Beginning of Period
Additions Charged to Costs and Expenses
Discounts on Purchased Receivables
Net Accounts Receivable Recovered (Written-Off)
Balance at End of Period
Three Months Ended December 31, 2021
Allowance for Uncollectible Accounts
$
31,639
$
3,742
$
161
$
57
$
35,599
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 $2.7 million at December 31, 2021, 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 (in thousands):
At December 31, 2021
At September 30, 2021
Materials and Supplies - at average cost
$
36,233
$
34,880
Emission Allowances
11,118
18,680
$
47,351
$
53,560
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 $2.0 billion and $1.9 billion at December 31, 2021 and September 30, 2021, 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 $120.0 million and $103.8 million at December 31, 2021 and September 30, 2021, 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 unproved 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. At December 31, 2021, the ceiling exceeded the book value of the oil and gas properties by approximately $1.3 billion. In adjusting estimated
future net cash flows for hedging under the ceiling test at December 31, 2021, estimated future net cash flows were decreased by $297.8 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. There were no indications of any impairments to property, plant and equipment in the Utility, Pipeline and Storage and Gathering segments at December 31, 2021.
Accumulated Other Comprehensive Loss. The components of Accumulated Other Comprehensive Loss and changes for the three months ended December 31, 2021 and 2020, 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, 2021
Balance at October 1, 2021
$
(449,962)
$
(63,635)
$
(513,597)
Other Comprehensive Gains and Losses Before Reclassifications
118,483
—
118,483
Amounts Reclassified From Other Comprehensive Income
118,088
—
118,088
Balance at December 31, 2021
$
(213,391)
$
(63,635)
$
(277,026)
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
225
—
225
Balance at December 31, 2020
$
10,151
$
(89,892)
$
(79,741)
Reclassifications Outof Accumulated Other Comprehensive Loss. The details about the reclassification adjustments out of accumulated other comprehensive loss for the three months ended December 31, 2021 and 2020 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands):
Details About Accumulated Other Comprehensive Loss Components
Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Loss
Affected Line Item in the Statement Where Net Income is Presented
Three Months Ended December 31,
2021
2020
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
Other Current Assets. The components of the Company’s Other Current Assets are as follows (in thousands):
At December 31, 2021
At September 30, 2021
Prepayments
$
12,997
$
14,164
Prepaid Property and Other Taxes
15,366
14,788
State Income Taxes Receivable
3,516
1,502
Regulatory Assets
32,435
29,206
$
64,314
$
59,660
Other Accruals and Current Liabilities. The components of the Company’s Other Accruals and Current Liabilities are as follows (in thousands):
At December 31, 2021
At September 30, 2021
Accrued Capital Expenditures
$
51,685
$
42,541
Regulatory Liabilities
22,937
60,860
Reserve for Gas Replacement
2,724
—
Liability for Royalty and Working Interests
43,138
31,483
Federal Income Taxes Payable
79
154
Non-Qualified Benefit Plan Liability
15,408
15,408
Other
51,994
43,723
$
187,965
$
194,169
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, 2021, 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 8,732 securities and 373,378 securities excluded as being antidilutive for the quarters ended December 31, 2021 and December 31, 2020, respectively.
Stock-Based Compensation. The Company granted 195,397 performance shares during the quarter ended December 31, 2021. The weighted average fair value of such performance shares was $65.39 per share for the quarter ended December 31, 2021. 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.
The performance shares granted during the quarter ended December 31, 2021 include awards that must meet a performance goal related to either relative return on capital over a three-year performance cycle ("ROC performance shares"), methane intensity and greenhouse gas emissions reductions over a three-year performance cycle ("ESG performance shares") or relative shareholder return over a three-year performance cycle ("TSR performance shares"). The performance goal related to the ROC performance shares over the three-year 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 ROC 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 the ROC 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 performance goal related to the ESG performance shares over the three-year performance cycle consists of two parts: reductions in the rates of intensity of methane emissions for each of the Company's operating segments, and reduction of the consolidated Company's total greenhouse gas emissions. The Company's Compensation Committee set specific target levels for methane intensity rates and total greenhouse gas emissions, and the performance goal is intended to incentivize and reward performance that helps position the Company to meet or exceed its 2030 methane intensity and greenhouse gas reduction targets. The number of these ESG performance shares that will vest and be paid out will depend upon the number of methane intensity segment targets achieved and whether the Company meets the total greenhouse gas emissions target. The fair value of these ESG 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 performance goal related to the TSR performance shares over the three-year 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 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 127,295 restricted stock units during the quarter ended December 31, 2021. The weighted average fair value of such restricted stock units was $54.06 per share for the quarter ended December 31, 2021. 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.
Note 2 – Asset Acquisitions and Divestitures
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. These 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 2021 Form 10-K for additional information concerning the Company’s acquisition of certain upstream assets and midstream gathering assets from Shell.
The following tables provide a disaggregation of the Company's revenues for the three months ended December 31, 2021 and 2020, presented by type of service from each reportable segment.
Quarter Ended December 31, 2021 (Thousands)
Revenues By Type of Service
Exploration and Production
Pipeline and Storage
Gathering
Utility
All Other
Corporate and Intersegment Eliminations
Total Consolidated
Production of Natural Gas
$
361,282
$
—
$
—
$
—
$
—
$
—
$
361,282
Production of Crude Oil
42,371
—
—
—
—
—
42,371
Natural Gas Processing
1,029
—
—
—
—
—
1,029
Natural Gas Gathering Service
—
—
52,225
—
—
(48,180)
4,045
Natural Gas Transportation Service
—
66,269
—
27,775
—
(17,625)
76,419
Natural Gas Storage Service
—
20,800
—
—
—
(9,024)
11,776
Natural Gas Residential Sales
—
—
—
179,011
—
—
179,011
Natural Gas Commercial Sales
—
—
—
23,998
—
—
23,998
Natural Gas Industrial Sales
—
—
—
1,147
—
—
1,147
Other
2,145
1,281
—
(2,000)
6
(152)
1,280
Total Revenues from Contracts with Customers
406,827
88,350
52,225
229,931
6
(74,981)
702,358
Alternative Revenue Programs
—
—
—
6,828
—
—
6,828
Derivative Financial Instruments
(162,629)
—
—
—
—
—
(162,629)
Total Revenues
$
244,198
$
88,350
$
52,225
$
236,759
$
6
$
(74,981)
$
546,557
Quarter Ended December 31, 2020 (Thousands)
Revenues By Type of Service
Exploration and Production
Pipeline and Storage
Gathering
Utility
All Other
Corporate and Intersegment Eliminations
Total Consolidated
Production of Natural Gas
$
166,442
$
—
$
—
$
—
$
—
$
—
$
166,442
Production of Crude Oil
24,499
—
—
—
—
—
24,499
Natural Gas Processing
553
—
—
—
—
—
553
Natural Gas Gathering Service
—
—
47,009
—
—
(46,658)
351
Natural Gas Transportation Service
—
64,825
—
29,021
—
(19,590)
74,256
Natural Gas Storage Service
—
20,517
—
—
—
(8,763)
11,754
Natural Gas Residential Sales
—
—
—
137,881
—
—
137,881
Natural Gas Commercial Sales
—
—
—
17,195
—
—
17,195
Natural Gas Industrial Sales
—
—
—
922
—
—
922
Natural Gas Marketing
—
—
—
—
585
(20)
565
Other
211
2,422
—
(1,612)
545
(108)
1,458
Total Revenues from Contracts with Customers
191,705
87,764
47,009
183,407
1,130
(75,139)
435,876
Alternative Revenue Programs
—
—
—
5,594
—
—
5,594
Derivative Financial Instruments
(310)
—
—
—
—
—
(310)
Total Revenues
$
191,395
$
87,764
$
47,009
$
189,001
$
1,130
$
(75,139)
$
441,160
The Company records revenue related to its derivative financial instruments in the Exploration and Production segment. The Company also records revenue related to alternative revenue programs in its Utility segment. Revenue related to
derivative financial instruments and alternative revenue programs are excluded from the scope of the authoritative guidance regarding revenue recognition 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: $165.2 million for the remainder of fiscal 2022; $184.1 million for fiscal 2023; $161.0 million for fiscal 2024; $153.4 million for fiscal 2025; $133.5 million for fiscal 2026; and $787.4 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, 2021 and September 30, 2021. 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.
(1)Netting Adjustments represent the impact of legally-enforceable master netting arrangements that allow the Company to net gain and loss positions held with the same counterparties. The net asset or net liability for each counterparty is recorded as an asset or liability on the Company’s balance sheet.
Derivative Financial Instruments
The derivative financial instruments reported in Level 2 at December 31, 2021 and September 30, 2021 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. Hedging collateral deposits of $88.6 million (at September 30, 2021), which were associated with the price swap agreements, no cost collars and foreign currency contracts, have been reported in Level 1 at September 30, 2021. There were no hedging collateral deposits at December 31, 2021. 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 authoritative guidance 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, 2021, 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, 2021 and December 31, 2020, 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, 2021
September 30, 2021
Carrying Amount
Fair Value
Carrying Amount
Fair Value
Long-Term Debt
$
2,629,602
$
2,847,638
$
2,628,687
$
2,898,552
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 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, 2021
At September 30, 2021
Life Insurance Contracts
$
45,599
$
44,560
Equity Mutual Fund
25,442
34,433
Fixed Income Mutual Fund
35,442
70,639
$
106,483
$
149,632
Investments in life insurance contracts are stated at their cash surrender values or net present value. Investments in an equity mutual fund and a fixed income mutual fund are stated at fair value based on quoted market prices with changes in fair value recognized in net income. The insurance contracts and equity mutual fund are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees. The fixed income mutual fund is primarily an informal funding mechanism for certain regulatory obligations that the Company has to Utility segment customers in its Pennsylvania jurisdiction, as discussed in Note 11 — Regulatory Matters, and 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 9 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, 2021 and September 30, 2021. 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 financial 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, 2021, the Company had the following commodity derivative contracts (swaps and no cost collars) outstanding:
Commodity
Units
Natural Gas
371.2
Bcf
Crude Oil
1,692,000
Bbls
As of December 31, 2021, the Company was hedging a total of $56.7 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts.
As of December 31, 2021, the Company had $290.7 million ($213.4 million after-tax) of net hedging losses included in the accumulated other comprehensive loss balance. It is expected that $197.7 million ($145.1 million after-tax) of such unrealized losses 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, 2021 and 2020 (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,
2021
2020
2021
2020
Commodity Contracts
$
163,126
$
45,595
Operating Revenue
$
(162,629)
$
(310)
Foreign Currency Contracts
6
2,426
Operating Revenue
41
(1)
Total
$
163,132
$
48,021
$
(162,588)
$
(311)
Credit Risk
The Company has over-the-counter swap positions, no cost collars and applicable foreign currency forward contracts with seventeen counterparties. The majority of the Company’s counterparties are financial institutions and energy traders. As of December 31, 2021, fifteen of the seventeen counterparties to the Company’s outstanding derivative financial 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 post or 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 financial instrument contracts with a credit-risk contingency feature were in a liability position (or if the liability were larger) and/or the Company’s credit rating declined, then hedging collateral deposits or an increase to such deposits could be required. At December 31, 2021, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $235.2 million according to the Company’s internal model (discussed in Note 4 – Fair Value Measurements), and no hedging collateral deposits were required to be posted by the Company at December 31, 2021. Depending on the movement of commodity prices in the future, it is possible that these liability positions could swing into asset positions, at which point the Company would be exposed to credit risk on its derivative financial instruments. In that case, the Company's counterparties could be required to post hedging collateral deposits.
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.
The effective tax rates for the quarters ended December 31, 2021 and December 31, 2020 were 25.3% and 27.4%, respectively. The decrease in the effective tax rate is primarily due to differences between the book and tax treatment of equity compensation and the utilization of the Enhanced Oil Recovery credit in fiscal 2022 that was phased out for fiscal 2021.
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, 2021
91,182
$
91,182
$
1,017,446
$
1,191,175
$
(513,597)
Net Income Available for Common Stock
132,392
Dividends Declared on Common Stock ($0.455 Per Share)
(41,604)
Other Comprehensive Income, Net of Tax
236,571
Share-Based Payment Expense (1)
5,039
Common Stock Issued (Repurchased) Under Stock and Benefit Plans
255
255
(8,664)
Balance at December 31, 2021
91,437
$
91,437
$
1,013,821
$
1,281,963
$
(277,026)
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)
(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, 2021, the Company issued 17,943 original issue shares of common stock as a result of SARs exercises, 110,339 original issue shares of common stock for restricted stock units that vested and 265,607 original issue shares of common stock for performance shares that vested. The Company also issued 8,395 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, including the reinvestment of dividends for certain non-employee directors who elected to defer their shares pursuant to the dividend reinvestment feature of the Company's Deferred Compensation Plan for Directors and Officers during the three months ended December 31, 2021. 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, 2021, 146,996 shares of common stock were tendered to the Company for such purposes. The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law.
Current Portion of Long-Term Debt.None of the Company's long-term debt as of December 31, 2021 and September 30, 2021 had a maturity date within the following twelve-month period.
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, 2021, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $3.1 million. The Company's liability for such clean-up costs has been recorded in Other Liabilities on the Consolidated Balance Sheet at December 31, 2021. The Company expects to recover its environmental clean-up costs through rate recovery over a period of approximately one year 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). Subsequently, 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 were appealed. The Second Circuit Court of Appeals issued an order upholding the FERC waiver orders. 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 and, on January 28, 2022, filed with FERC a request for an extension of time to construct 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 reconcile to consolidated amounts. As stated in the 2021 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 2021 Form 10-K. A listing of segment assets at December 31, 2021 and September 30, 2021 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,
2021
2020
2021
2020
Service Cost
$
2,190
$
2,466
$
332
$
400
Interest Cost
5,707
5,422
2,267
2,326
Expected Return on Plan Assets
(13,074)
(14,537)
(7,340)
(7,241)
Amortization of Prior Service Cost (Credit)
134
158
(107)
(107)
Amortization of (Gains) Losses
6,601
9,203
(1,903)
212
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)
4,420
3,713
6,246
6,854
Net Periodic Benefit Cost (Income)
$
5,978
$
6,425
$
(505)
$
2,444
(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, 2021, 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 2022, the Company expects its contributions to the Retirement Plan to be in the range of $15.0 million to $20.0 million. In the remainder of 2022, 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.
On August 13, 2021, the NYPSC issued an order extending the date through which qualified pipeline replacement costs incurred by the Company can be recovered using the existing system modernization tracker for two years (until March 31, 2023). The extension is contingent on the Company not filing a base rate case that would result in new rates becoming effective prior to April 1, 2023.
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
law that prohibited utilities from terminating or disconnecting services to any residential customer for non-payment for the duration of the state disaster emergency. While that legislation expired on March 31, 2021, new legislation was enacted in May 2021 that prohibited utility terminations for non-payment for residential and small commercial customers who experienced a change in financial circumstances due to the COVID-19 state of emergency, with such prohibition running for a period of one hundred eighty days after either the New York State COVID-19 state of emergency is lifted or expires or December 31, 2021, whichever is earlier. On June 24, 2021, the New York State COVID-19 state of emergency expired. Updated guidance issued by the NYPSC on July 6, 2021 confirmed that qualified customers are protected from termination through December 21, 2021 and are eligible for a deferred payment agreement without the requirement of a down payment, late fees, penalties or interest on arrears incurred during the COVID-19 state of emergency. On December 20, 2021, NYPSC Staff requested, and the Company agreed, to refrain from terminating residential customers with a pending application for arrears payments through the Emergency Rental Assistance Program administered by the Office of Temporary Disability.
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 July 22, 2021, Distribution Corporation filed a supplement to its current Pennsylvania tariff proposing to reduce base rates effective October 1, 2021 by $7.7 million in order to stop collecting other post-employment benefit (“OPEB”) expenses from customers at this time, to begin to refund to customers overcollected OPEB expenses in the amount of $50.0 million, and to make certain other adjustments to further reduce Distribution Corporation’s regulatory liability associated with OPEB expenses. The PaPUC issued an order approving this tariff supplement on September 15, 2021 and new rates went into effect on October 1, 2021. On September 21, 2021, a complaint was filed in this proceeding. While new rates, including associated refunds, went into effect on October 1, 2021, certain other adjustments called for by the tariff supplement that allow Distribution Corporation to reduce its regulatory liability and its OPEB expenses will not be recorded in the Company’s consolidated financial statements until the complaint is resolved. The PaPUC assigned the matter to an Administrative Law Judge who, on January 6, 2022, issued a Recommended Decision approving a settlement reached by parties to the complaint proceeding. The matter currently sits with the PaPUC for final determination. The refunds specified in the tariff supplement will be funded entirely by grantor trust assets held by the Company, most of which are included in a fixed income mutual fund that is a component of Other Investments on the Company’s Consolidated Balance Sheet. With the elimination of OPEB expenses in base rates, Distribution Corporation will no longer fund the grantor trust or its VEBA trusts in its Pennsylvania jurisdiction.
FERC Jurisdiction
Supply Corporation’s 2020 rate settlement 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.
Empire’s 2019 rate settlement provides that Empire must make a rate case filing no later than May 1, 2025.
Note 12 – Leases
In October 2021, the Company executed two lease contracts for drilling rig services in Pennsylvania with lease terms of greater than one year. One of the new lease contracts commenced in December 2021 with estimated lease payments of $8.4 million over the lease term. This lease has been recognized on the Consolidated Balance Sheet at December 31, 2021. A right-of-use operating lease asset of $8.1 million is recorded in Deferred Charges, the current portion of the operating lease liability ($7.2 million) is recorded in Other Accruals and Current Liabilities, and the noncurrent portion of the operating lease liability ($0.9 million) is recorded in Other Liabilities. The second lease contract, which is also an operating lease, commenced in January 2022 with estimated lease payments of $11.9 million over the lease term.
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 customers 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 Part I, Item 1A, Risk Factors, under Operational Risks in the Company's 2021 Form 10-K for a more complete discussion of the risks to the Company associated with the COVID-19 pandemic.
The Company has continued to pursue development projects to expand its Pipeline and Storage segment. One project on Supply Corporation's system, referred to as the FM100 Project, upgraded a 1950’s era pipeline in northwestern Pennsylvania and created 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 ("Transco") system at Leidy, Pennsylvania. Construction activities on the expansion portion of the FM100 Project are complete and the project was placed in service in December 2021. The final project cost is estimated to be $230 million. This project is expected to provide incremental annual transportation revenues of approximately $50 million. The FM100 Project is discussed in more detail in the Capital Resources and Liquidity section that follows. For further discussion of the Pipeline and Storage segment's revenues and earnings, refer to the Results of Operations section below.
Seneca’s 330,000 Dth per day of incremental pipeline capacity on the Leidy South Project, which is the companion project to the Company's FM100 Project, went in service in December 2021. The incremental pipeline capacity from this project and associated gathering system development by Midstream Company allows Seneca to increase its production and reach premium Transco Zone 6 (Non-New York) markets.
From a financing perspective, the Company expects to use cash on hand and cash from operations, as well as short-term borrowings, to meet its financing needs for fiscal 2022.
CRITICAL ACCOUNTING ESTIMATES
For a complete discussion of critical accounting estimates, refer to "Critical Accounting Estimates" in Item 7 of the Company's 2021 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. At December 31, 2021, the ceiling exceeded the book value of the oil and gas properties by approximately $1.3 billion. 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, 2021, based on posted Midway Sunset prices, was $65.70 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, 2021, based on the quoted Henry Hub spot price for natural gas, was $3.60 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, 2021. 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 amounts the ceiling would have exceeded the book value of the Company's oil and gas properties at December 31, 2021 if natural gas prices were $0.25 per MMBtu lower than the average prices used at December 31, 2021, if crude oil prices were $5 per Bbl lower than the average prices used at December 31, 2021, and 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, 2021 (all amounts are presented after-tax). In all cases, these price decreases would not have resulted in an impairment charge. 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
Excess of Ceiling over Book Value under Sensitivity Analysis
$
1,004.0
$
1,249.0
$
968.4
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 2021 Form 10-K.
RESULTS OF OPERATIONS
Earnings
The Company's earnings were $132.4 million for the quarter ended December 31, 2021 compared to earnings of $77.8 million for the quarter ended December 31, 2020. The increase in earnings of $54.6 million is primarily the result of higher earnings in the Exploration and Production segment, Gathering segment and Pipeline and Storage segment. Lower earnings in the Utility segment, as well as losses in the Corporate and All Other categories, partially offset these increases.
The Company's earnings for the quarter ended December 31, 2020 included a non-cash impairment charge of $76.2 million ($55.2 million after-tax) for the Exploration and Production segment's oil and gas producing properties. The Company's earnings for the quarter ended December 31, 2020 also included 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. 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 $52.8 million for the quarter ended December 31, 2021 as compared with the quarter ended December 31, 2020. Gas production revenue after hedging increased $43.3 million due to the impact of a 5.7 Bcf increase in natural gas production, together with a $0.38 per Mcf increase in the weighted average price of natural gas after hedging. Natural gas production increased largely due to additional production from the Company's new Marcellus and Utica wells in the Appalachian region. Oil production revenue after hedging increased $7.1 million due to an increase in the weighted average price of oil after hedging of $14.38 per Bbl, offset by the impact of a 15 Mbbl decrease in oil production. The decrease in oil production was largely due to natural production declines. In addition, other revenue increased $1.9 million and gas processing plant revenue increased $0.5 million. The increase in other revenue is primarily attributed to a temporary capacity release for a small portion of this segment's Leidy South transportation contract combined with operating revenue for the Highland Field Services water treatment plants acquired at the end of fiscal year 2021.
The Exploration and Production segment's earnings for the quarter ended December 31, 2021 were $62.4 million, an increase of $92.0 million when compared with a loss of $29.6 million for the quarter ended December 31, 2020. The increase in earnings was due to a quarter ended December 31, 2020 non-cash impairment of oil and gas properties ($55.2 million), higher natural gas production ($9.6 million), higher natural gas prices after hedging ($24.6 million), higher oil prices after hedging ($6.2 million), higher other operating revenue ($1.5 million), lower interest expense ($2.7 million) and lower income tax expense ($0.9 million). The positive earnings impact of these items was partially offset by lower oil production ($0.6 million), higher lease operating and transportation expenses ($2.8 million), higher depletion expense ($3.3 million), higher other operating expenses ($1.3 million) and higher other taxes ($1.0 million). The decrease in interest expense can largely be attributed to lower intercompany long-term and short-term borrowings combined with lower rates. The increase in lease operating and transportation expenses was primarily the result of increased gathering and transportation costs in the Appalachian region due to increased production combined with higher steam fuel costs in the West Coast region due to higher nature gas prices. The increase in depletion expense was primarily due to the net increase in production. The increase in other operating expense was partially attributed to an increase in personnel costs combined with an increase in operating costs associated with the Highland Field Services water treatment plants acquired at the end of fiscal year 2021. The increase in other taxes was mainly attributed to increased Impact Fees in the Appalachian region. Impact Fees are variable fees that move based on calendar year NYMEX prices.
Operating revenues for the Pipeline and Storage segment increased $0.6 million for the quarter ended December 31, 2021 as compared with the quarter ended December 31, 2020. The increase in operating revenues was primarily due to an increase in transportation revenues of $1.4 million and an increase in storage revenues of $0.3 million, partially offset by a decrease in other revenue of $1.1 million. The increase in transportation revenues was primarily attributable to new demand charges for transportation service from Supply Corporation's FM100 Project, which was placed into service in December 2021, partially offset by revenue decreases associated with miscellaneous contract terminations and revisions. In addition, a surcharge for Pipeline Safety and Greenhouse Gas Regulatory Costs (PS/GHG Regulatory Costs) that went into effect in November 2020 associated with Supply Corporation’s 2020 rate case settlement also contributed to the increase in transportation revenues and was primarily responsible for the increase in storage revenues. The decrease in other revenue primarily reflects the non-recurrence of revenue associated with a contract buyout that occurred during the quarter ended December 31, 2020, partially offset by higher revenues recorded under surcharge mechanisms to match higher purchased gas and electric power costs for Empire’s compressor stations.
Transportation volume for the quarter ended December 31, 2021 decreased by 9.3 Bcf from the prior year's quarter, primarily due to lower throughput related to warmer weather than the prior year, partially offset by an increase in volume from the FM100 Project, which was brought online in December 2021. 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, 2021 were $25.2 million, an increase of $1.0 million when compared with earnings of $24.2 million for the quarter ended December 31, 2020. The increase in earnings was primarily due to the earnings impact of higher operating revenues of $0.5 million, as discussed above, and an increase in other income ($1.2 million). The increase in other income was mainly due to an increase in allowance for funds used during construction (equity component) related to the construction of the FM100 Project. These earnings increases were partially offset by an increase in operating expenses ($0.8 million) primarily due to an increase in personnel costs and higher power costs, related to Empire's electric motor drive compressor station. Empire also experienced higher purchased gas costs ($0.3 million) related to its natural gas driven compressor stations. The power costs and purchased gas costs are offset by an equal amount of revenue due to surcharge mechanisms.
Operating revenues for the Gathering segment increased $5.2 million for the quarter ended December 31, 2021 as compared with the quarter ended December 31, 2020, which was driven primarily by a 12.7 Bcf increase in gathered volume. Contributors to the increase included the Trout Run, Clermont and Wellsboro gathering systems, which recorded increases of 11.3 Bcf, 4.0 Bcf and 1.3 Bcf, respectively, partially offset by the Covington gathering system, which recorded a decrease of 3.9 Bcf. The net increase in gathered volume can be attributed primarily to an increase in non-affiliated natural gas production on the Trout Run gathering system in the Appalachian region and, to a lesser extent, an increase in Seneca's gross natural gas production in the Appalachian region.
The Gathering segment’s earnings for the quarter ended December 31, 2021 were $23.1 million, an increase of $2.5 million when compared with earnings of $20.6 million for the quarter ended December 31, 2020. The increase in earnings was mainly due to higher gathering revenues ($4.1 million) driven by the increase in gathered volume, as discussed above. This earnings increase was partially offset by higher operating expenses ($0.8 million) and higher depreciation expense ($0.4 million). The increase in operating expenses was largely attributable to higher outside services costs associated with preventative maintenance overhauls on the Trout Run gathering system. The increase in depreciation expense was largely due to higher plant balances associated with the Clermont gathering system. Earnings also decreased due to higher income tax expense ($0.2 million).
(1)Percents compare actual 2021 degree days to normal degree days and actual 2021 degree days to actual 2020 degree days.
2021 Compared with 2020
Operating revenues for the Utility segment increased $47.8 million for the quarter ended December 31, 2021 as compared with the quarter ended December 31, 2020. The increase resulted from a $49.1 million increase in retail gas sales revenue, which was primarily due to a significant increase in the cost of gas sold (per Mcf). Under its purchased gas adjustment clauses in New York and Pennsylvania, Distribution Corporation is not allowed to profit from fluctuations in gas costs. This increase was partially offset by a $1.0 million decrease in transportation revenues and a $0.4 million decrease in other revenues. The decline in transportation revenues was largely the result of a 0.3 Bcf decrease in transportation throughput due to warmer weather and the migration of residential transportation customers to retail. The decrease in other revenues was mainly the result of a regulatory adjustment ($0.9 million) and lower late payment charges billed to customers ($0.5 million), partially offset by a smaller estimated refund provision for the income tax benefits resulting from the 2017 Tax Reform Act ($0.7 million) and an increase in capacity release revenues ($0.3 million).
The Utility segment’s earnings for the quarter ended December 31, 2021 were $22.1 million, a decrease of $0.9 million when compared with earnings of $23.0 million for the quarter ended December 31, 2020. The decrease in earnings was largely attributable to a decrease in base rates that reflects the elimination of other post-employment benefit (“OPEB”) expenses from customer rates in Distribution Corporation's Pennsylvania service territory in accordance with a regulatory proceeding that became effective October 1, 2021 ($1.8 million) combined with higher operating expenses ($1.4 million), primarily the result of higher personnel costs and outside services that were partially offset by a decrease in the allowance for uncollectible accounts. The impact of regulatory revenue adjustments ($0.9 million) and higher depreciation expense ($0.7 million) due to higher plant balances also contributed to the decrease in earnings. These decreases were partially offset by a lower effective tax rate ($2.0 million), lower other deductions ($1.7 million) largely related to the elimination of OPEB expenses from customer rates, as discussed above, and the impact of a system modernization tracker in New York ($0.8 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, 2021, the WNC increased earnings by approximately $2.6 million, as the weather was warmer than normal. For the quarter ended December 31, 2020, the WNC increased earnings by approximately $1.6 million, as the weather was warmer than normal.
Corporate and All Other operations had a loss of $0.4 million for the quarter ended December 31, 2021, a decrease of $40.0 million when compared with earnings of $39.6 million for the quarter ended December 31, 2020. The decrease in earnings was primarily attributable to the non-recurrence of a $51.1 million gain ($37.0 million gain after-tax) on sale of timber properties recorded by Seneca's Northeast Division during the quarter ended December 31, 2020. The decrease can also be attributed to changes in unrealized losses on investments in equity securities. During the quarter ended December 31, 2021, the Company recorded unrealized losses of $3.5 million. During the quarter ended December 31, 2020, the Company recorded unrealized losses of $1.0 million.
Other Income (Deductions)
Net other deductions on the Consolidated Statement of Income were $1.1 million for the quarter ended December 31, 2021, compared to net other deductions of $2.2 million for the quarter ended December 31, 2020. This change is primarily attributable to a decrease in the pension and post-retirement non-service benefit cost expense of $3.0 million largely relating to the elimination of OPEB expenses from customer rates in the Utility segment's Pennsylvania service territory in accordance with a tariff supplement that became effective October 1, 2021. Also contributing to the decrease in other deductions is an increase in allowance for funds used during construction (equity component) of $1.1 million. These were partially offset by changes in realized and unrealized gains and losses on investments in equity securities. During the quarter ended December 31, 2021, the Company recorded pre-tax realized gains of $4.4 million and pre-tax unrealized losses of $5.2 million. During the quarter ended December 31, 2020, the Company recorded pre-tax realized gains of $3.3 million and pre-tax unrealized losses of $1.1 million.
Interest Expense on Long-Term Debt
Interest expense on long-term debt on the Consolidated Statement of Income decreased $2.1 million for the quarter ended December 31, 2021 as compared to the quarter ended December 31, 2020 primarily due to a lower weighted average interest rate on long-term debt, stemming from the Company's issuance of $500.0 million of 2.95% notes in February 2021, which replaced $500.0 million of 4.90% notes that were retired in March 2021.
CAPITAL RESOURCES AND LIQUIDITY
The Company’s primary sources of cash during the three-month period ended December 31, 2021 consisted of cash provided by operating activities and proceeds from the sale of a fixed income mutual fund in a grantor trust. 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 expects to have adequate amounts of cash to meet both its short-term and long-term cash requirements. During the remainder of 2022, cash provided by operating activities is expected to increase over the amount of cash provided by operating activities during 2021 and will be used to meet the Company's dividend requirements and reduce short-term borrowings. Capital expenditures for 2022 are expected to be lower than 2021. There are no scheduled repayments of long-term debt in the remainder of 2022. Looking at 2023 through 2024, based on current commodity prices, cash provided by operating activities is expected to exceed capital expenditures in each of those years, which could lead to further capital investments in the business or reductions in short-term borrowings and a net reduction in long-term debt in 2023 while still allowing the Company to meet its dividend requirements. These cash flow projections do not reflect the impact of acquisitions or divestitures that may arise in the future.
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, gains and losses associated with investing and financing activities, and changes in operating assets and liabilities. Non-cash items include depreciation, depletion and amortization, impairment of oil and gas producing 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 $171.5 million for the three months ended December 31, 2021, a decrease of $33.2 million compared with $204.7 million provided by operating activities for the three months ended December 31, 2020. The decrease in cash provided by operating activities primarily reflects lower cash provided by operating activities in the Utility segment, slightly offset by higher cash provided by operating activities in the Exploration and Production segment. The decrease in the Utility segment is primarily due to lower rates in the Utility segment's Pennsylvania service territory that went into effect October 1, 2021 combined with the timing of gas cost recovery and other regulatory true-ups. The rates that went into effect included a one-time customer bill credit of $25 million in October 2021 for previously overcollected OPEB expenses and the beginning of a 5-year pass back of an additional $25 million in previously overcollected OPEB expenses. Please refer to the Rate Matters section that follows for additional discussion of this matter. The increase in the Exploration and Production segment was primarily due to higher cash receipts from natural gas production.
Investing Cash Flow
Expenditures for Long-Lived Assets
The Company’s expenditures for long-lived assets totaled $191.8 million during the three months ended December 31, 2021 and $150.9 million during the three months ended December 31, 2020. The table below presents these expenditures:
Total Expenditures for Long-Lived Assets
Three Months Ended December 31,
2021
2020
Increase (Decrease)
(Millions)
Exploration and Production:
Capital Expenditures
$
139.2
(1)
$
81.3
(2)
$
57.9
Pipeline and Storage:
Capital Expenditures
24.1
(1)
43.7
(2)
(19.6)
Gathering:
Capital Expenditures
8.9
(1)
8.3
(2)
0.6
Utility:
Capital Expenditures
19.4
(1)
17.3
(2)
2.1
All Other:
Capital Expenditures
0.2
0.1
0.1
Eliminations
—
0.2
(0.2)
$
191.8
$
150.9
$
40.9
(1)At December 31, 2021, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $69.9 million, $5.4 million, $2.6 million and $3.1 million, respectively, of non-cash capital expenditures. At September 30,
2021, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $47.9 million, $39.4 million, $4.8 million and $10.6 million, respectively, of non-cash capital expenditures.
(2)At December 31, 2020, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $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.
Exploration and Production
The Exploration and Production segment capital expenditures for the three months ended December 31, 2021 were primarily well drilling and completion expenditures and included approximately $132.1 million for the Appalachian region (including $45.1 million in the Marcellus Shale area and $83.3 million in the Utica Shale area) and $7.1 million for the West Coast region. These amounts included approximately $54.2 million spent to develop proved undeveloped reserves.
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.
Pipeline and Storage
The Pipeline and Storage segment capital expenditures for the three months ended December 31, 2021 were primarily for expenditures related to Supply Corporation's FM100 Project ($15.7 million), which is discussed below. In addition, the Pipeline and Storage segment capital expenditures for the three months ended December 31, 2021 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, 2020 were primarily for expenditures related to Supply Corporation's FM100 Project ($30.4 million). 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.
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.
Supply Corporation has developed its FM100 Project, which upgraded a 1950's era pipeline in northwestern Pennsylvania and created 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. Supply Corporation and Transco executed a precedent agreement whereby Transco has leased this additional capacity ("Lease") as part of a Transco expansion project ("Leidy South"), creating 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. Construction activities on the expansion portion of the FM100 project are complete and the project commenced partial in-service on December 1, 2021, with full in-service on December 19, 2021. Abandonment activities on the project will continue in calendar year 2022. The estimated capital cost of the project is approximately $230 million. As of December 31, 2021, approximately $201.8 million has been spent on the FM100 project, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at December 31, 2021.
Supply Corporation and Empire have developed a project which would move significant prospective Marcellus and Utica 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).
Subsequently, 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 were appealed. The Second Circuit Court of Appeals issued an order upholding the FERC waiver orders. 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 and, on January 28, 2022, filed with FERC a request for an extension of time to construct 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 timing of receipt of necessary regulatory approvals. As of December 31, 2021, approximately $55.7 million has been spent on the Northern Access project, including $24.1 million that has been spent to study the project. The remaining $31.6 million spent on the project is included in Property, Plant and Equipment on the Consolidated Balance Sheet at December 31, 2021.
Gathering
The majority of the Gathering segment capital expenditures for the three months ended December 31, 2021 included expenditures related to the continued expansion of Midstream Company's Clermont and Covington gathering systems, as discussed below. Midstream Company spent $4.0 million and $4.5 million, respectively, during the three months ended December 31, 2021 on the development of the Clermont and Covington gathering systems. These expenditures were largely attributable to new Clermont gathering pipelines, as well as the development of new gathering facilities, including new gathering pipelines and upgrades to existing stations, in the Tioga gathering system, which is part of Midstream Covington.
The majority of the Gathering segment capital expenditures for the three months ended December 31, 2020 were for the continued expansion of Midstream Company's Clermont and Wellsboro gathering systems. 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.
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 Covington, LLC, a wholly-owned subsidiary of Midstream Company, operates its Covington gathering system as well as the Tioga gathering system acquired from Shell on July 31, 2020, both in Tioga County, Pennsylvania. The current Covington gathering system consists of two compressor stations and backbone and in-field gathering pipelines. The Tioga gathering system consists of 13 compressor stations and backbone and in-field gathering pipelines.
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.
Utility
The majority of the Utility segment capital expenditures for the three months ended December 31, 2021 and December 31, 2020 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.
Other Investing Activities
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 2021 Form 10-K for additional information concerning the Company’s acquisition of certain upstream assets and midstream gathering assets from Shell.
In October 2021, the Company sold fixed income mutual fund shares held in a grantor trust for proceeds of $30 million. The proceeds were used in the Utility segment’s Pennsylvania service territory to fund a one-time customer bill credit of $25 million in October 2021 for previously overcollected OPEB expenses and the first year installment of a 5-year pass back of an additional $25 million in previously overcollected OPEB expenses in accordance with new rates that went into effect on October 1, 2021. Please refer to the Rate Matters section that follows for additional discussion of this matter.
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, 2021 and December 31, 2020, capital expenditures were funded with cash from operations. 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 most impacted by the timing of gas cost recovery in the Utility segment and by natural gas and crude oil production, and the associated commodity price realizations, in the Exploration and Production segment.
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, quicker development of existing oil and gas properties, natural gas storage and transmission 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 increased $7.5 million when comparing the balance sheet at December 31, 2021 to the balance sheet at September 30, 2021. The maximum amount of short-term debt outstanding during the quarter ended December 31, 2021 was $288.3 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. Given the significant rise in gas prices toward the end of fiscal 2021, the Company was required to post margin on some of its outstanding derivative financial instruments. At September 30, 2021, the Company had outstanding commercial paper of $158.5 million, approximately half of which was related to the aforementioned margin requirements. At December 31, 2021, the Company had outstanding commercial paper of $166.0 million, all of which was related to actual operating cash requirements. The Company was not required to post margin on its outstanding derivative financial instruments at December 31, 2021. The Company did not have any outstanding short-term notes payable to banks at December 31, 2021.
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, 2021, $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 .55. The constraints specified in both the Credit Agreement and Amended 364-Day Credit Agreement would have permitted an additional $1.47 billion in short-term and/or long-term debt to be outstanding at December 31, 2021 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.
None of the Company's long-term debt as of December 31, 2021 and September 30, 2021 had a maturity date within the following twelve-month period.
The Company’s embedded cost of long-term debt was 4.48% and 4.85% at December 31, 2021 and December 31, 2020, respectively.
Under the Company’s existing indenture covenants at December 31, 2021, the Company would have been permitted to issue up to a maximum of approximately $2.16 billion in additional unsubordinated long-term indebtedness at then current market interest rates, in addition to being able to issue new indebtedness to replace existing debt (further limited by debt to capitalization ratio constraints under the Company’s Credit Agreement and Amended 364-Day Credit Agreement, as discussed above). The Company's present liquidity position is believed to be adequate to satisfy known demands. It is possible, depending on amounts reported in various income statement and balance sheet line items, that the indenture covenants could, for a period of time, prevent the Company from issuing incremental unsubordinated long-term debt, or significantly limit the amount of such debt that could be issued. Losses incurred as a result of significant impairments of oil and gas properties have in the past resulted in such temporary restrictions. The indenture covenants would not preclude the Company from issuing new long-term debt to replace existing long-term debt, or from issuing additional short-term debt. 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, 2021) 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, 2021, 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 2022, the Company expects its contributions to the Retirement Plan to be in the range of $15.0 million to $20.0 million. In the remainder of 2022, the Company expects its contributions to its VEBA trusts to be in the range of $2.0 million to $2.5 million.
Market Risk Sensitive Instruments
On July 21, 2010, the Dodd-Frank Act was signed into law. The Dodd-Frank Act required the CFTC, SEC and other regulatory agencies to promulgate rules and regulations implementing the legislation, and 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. Rules developed by the CFTC and other regulators 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. Additionally, given the enforcement 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 authoritative guidance 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, 2021, 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 2021 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 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.
On August 13, 2021, the NYPSC issued an order extending the date through which qualified pipeline replacement costs incurred by the Company can be recovered using the existing system modernization tracker for two years (until March 31, 2023). The extension is contingent on the Company not filing a base rate case that would result in new rates becoming effective prior to April 1, 2023.
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 law that prohibited utilities from terminating or disconnecting services to any residential customer for non-payment for the duration of the state disaster emergency. While that legislation expired on March 31, 2021, new legislation was enacted in May 2021 that prohibited utility terminations for non-payment for residential and small commercial customers who experienced a change in financial circumstances due to the COVID-19 state of emergency, with such prohibition running for a period of one hundred eighty days after either the New York State COVID-19 state of emergency is lifted or expires or December 31, 2021, whichever is earlier. On June 24, 2021, the New York State COVID-19 state of emergency expired. Updated guidance issued by the NYPSC on July 6, 2021 confirmed that qualified customers are protected from termination through December 21, 2021 and are eligible for a deferred payment agreement without the requirement of a down payment, late fees, penalties or interest on arrears incurred during the COVID-19 state of emergency. On December 20, 2021, NYPSC Staff requested, and the Company agreed, to refrain from terminating residential customers with a pending application for arrears payments through the Emergency Rental Assistance Program administered by the Office of Temporary Disability.
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 July 22, 2021, Distribution Corporation filed a supplement to its current Pennsylvania tariff proposing to reduce base rates effective October 1, 2021 by $7.7 million in order to stop collecting other post-employment benefit (“OPEB”) expenses from customers at this time, to begin to refund to customers overcollected OPEB expenses in the amount of $50.0 million, and to make certain other adjustments to further reduce Distribution Corporation’s regulatory liability associated with OPEB expenses. The PaPUC issued an order approving this tariff supplement on September 15, 2021 and new rates went into effect on October 1, 2021. On September 21, 2021, a complaint was filed in this proceeding. While new rates, including associated refunds, went into effect on October 1, 2021, certain other adjustments called for by the tariff supplement that allow Distribution Corporation to reduce its regulatory liability and its OPEB expenses will not be recorded in the Company’s consolidated financial statements until the complaint is resolved. The PaPUC assigned the matter to an Administrative Law Judge who, on January 6, 2022, issued a Recommended Decision approving a settlement reached by parties to the complaint proceeding. The matter currently sits with the PaPUC for final determination. The refunds specified in the tariff supplement will be funded entirely by grantor trust assets held by the Company, most of which are included in a fixed income mutual fund that is a component of Other Investments on the Company’s Consolidated Balance Sheet. With the elimination of OPEB expenses in base rates, Distribution Corporation will no longer fund the grantor trust or its VEBA trusts in its Pennsylvania jurisdiction.
Pipeline and Storage
Supply Corporation’s 2020 rate settlement 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.
Empire’s 2019 rate settlement provides that Empire must make a rate case filing no later than May 1, 2025.
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 comply with regulatory requirements. In March 2021, the Company set greenhouse gas reduction targets associated with the Company's utility delivery system. To further our ongoing efforts to lower the Company's emissions profile, in September 2021 the Company also established methane intensity reduction targets at each of its businesses, as well as an absolute greenhouse gas emissions reduction target for the consolidated Company. The Company's ability to estimate accurately the time, costs and resources necessary to meet emissions targets may change as environmental exposures and opportunities change and regulatory updates are issued.
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 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. Additionally, other federal regulatory agencies are beginning to address greenhouse gas emissions through changes in their regulatory oversight approach and policies. A number of states have adopted energy strategies or plans with aggressive goals for the reduction of greenhouse gas emissions. In New York, the NYPSC, for example, initiated a proceeding to consider climate-related financial disclosures at the utility operating company level, and the New York State legislature passed the CLCPA that mandates reducing greenhouse gas emissions by 40% from 1990 levels by 2030, and by 85% from 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. 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. On April 23, 2021, California's Governor issued an executive order directing California Geologic Energy Management Division to stop issuing hydraulic fracturing permits by 2024, which does not have a direct impact on the plans of the Exploration and Production segment as those plans do not involve fracking. The executive order also directed the California Air Resources Board to investigate phasing out oil extraction by 2045, which may result in permitting delays and new legislative action in support of the directive. 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. 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. 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.
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 authoritative accounting and reporting guidance, 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.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;
2.Governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, target rates of return, rate design, retained natural gas and system modernization), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal;
3.The Company’s ability to estimate accurately the time and resources necessary to meet emissions targets;
4.Governmental/regulatory actions and/or market pressures to reduce or eliminate reliance on natural gas;
5.The length and severity of the ongoing COVID-19 pandemic, including its impacts across our businesses on demand, operations, global supply chains and liquidity;
6.Changes in economic conditions, including inflationary pressures and global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services;
7.Changes in the price of natural gas or oil;
8.The creditworthiness or performance of the Company’s key suppliers, customers and counterparties;
9.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;
10.Impairments under the SEC’s full cost ceiling test for natural gas and oil reserves;
11.Increased costs or delays or changes in 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;
12.The Company's ability to complete planned strategic transactions;
13.The Company's ability to successfully integrate acquired assets and achieve expected cost synergies;
14.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;
15.The impact of information technology disruptions, cybersecurity or data security breaches;
16.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;
17.Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits;
18.Other changes in price differentials between similar quantities of natural gas or oil having different quality, heating value, hydrocarbon mix or delivery date;
19.The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company;
20.Uncertainty of oil and gas reserve estimates;
21.Significant differences between the Company’s projected and actual production levels for natural gas or oil;
22.Changes in demographic patterns and weather conditions;
23.Changes in the availability, price or accounting treatment of derivative financial instruments;
24.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;
25.Economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities or acts of war;
26.Significant differences between the Company’s projected and actual capital expenditures and operating expenses; or
27.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, 2021.
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, 2021 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 2021 Form 10-K have not materially changed.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
On October 1, 2021, the Company issued a total of 8,210 unregistered shares of Company common stock to non-employee directors of the Company then serving on the Board of Directors of the Company (or, in the case of non-employee directors who elected to defer receipt of such shares pursuant to the Company's Deferred Compensation Plan for Directors and
Officers (the “DCP”), to the DCP trustee), consisting of 821 shares per director. All of these unregistered shares were issued under the Company’s 2009 Non-Employee Director Equity Compensation Plan (the “2009 Plan”) as partial consideration for such directors’ services during the quarter ended December 31, 2021. On October 15, 2021, the Company issued to the DCP trustee an additional 185 unregistered shares pursuant to the dividend reinvestment feature of the DCP, consisting of approximately 31 shares for each of the six directors who made a deferral election. 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, 2021
10,583
$57.78
—
6,971,019
Nov. 1 - 30, 2021
14,328
$59.11
—
6,971,019
Dec. 1 - 31, 2021
152,833
$60.37
—
6,971,019
Total
177,744
$60.13
—
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, 2021, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase program. Of the 177,744 shares purchased other than through a publicly announced share repurchase program, 30,748 were purchased for the Company's 401(k) plans and 146,996 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 Company has not repurchased any shares since September 17, 2008. The repurchase program has no expiration date and management would discuss with the Company's Board of Directors any future repurchases under this program.
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, 2021 and 2020, (ii) the Consolidated Statements of Comprehensive Income for the three months ended December 31, 2021 and 2020, (iii) the Consolidated Balance Sheets at December 31, 2021 and September 30, 2021, (iv) the Consolidated Statements of Cash Flows for the three months ended December 31, 2021 and 2020 and (v) the Notes to Condensed Consolidated Financial Statements.
Cover Page Interactive Data File (embedded within the Inline XBRL document)
••
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.
