☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2023
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, a 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 July 31, 2023: 91,819,306 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.
EAP
Energy Affordability Program; a program that provides bill discounts to gas customers who receive benefits under qualifying public assistance programs.
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.
Impact Fee
An annual fee imposed on unconventional wells spud in Pennsylvania. The fee is administered by the PaPUC and fees are distributed to counties and municipalities where the well is located.
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
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
Million British thermal units (heating value of one decatherm of natural gas)
MMcf
Million cubic feet (of natural gas)
NGA
The Natural Gas Act of 1938, as amended; the federal law regulating interstate natural gas pipeline and storage companies, among other things, codified beginning at 15 U.S.C. Section 717.
NYMEX
New York Mercantile Exchange. An exchange which maintains a futures market for crude oil and natural gas.
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.
SOFR
Secured Overnight Financing Rate
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/WNA
Weather normalization clause/adjustment; 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 Quarterly Report on 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, 2022, 2021 and 2020 that are included in the Company's 2022 Form 10-K. The consolidated financial statements for the year ended September 30, 2023 will be audited by the Company's independent registered public accounting firm after the end of the fiscal year.
The earnings for the nine months ended June 30, 2023 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2023. 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):
Nine Months Ended June 30, 2023
Nine Months Ended June 30, 2022
Balance at June 30, 2023
Balance at October 1, 2022
Balance at June 30, 2022
Balance at October 1, 2021
Cash and Temporary Cash Investments
$
53,415
$
46,048
$
432,576
$
31,528
Hedging Collateral Deposits
—
91,670
154,470
88,610
Cash, Cash Equivalents, and Restricted Cash
$
53,415
$
137,718
$
587,046
$
120,138
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 derivative financial instruments in an unrealized loss position. 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, the majority of which is in the Utility segment, is determined based on historical experience, the age of customer accounts, other specific information about customer accounts, and the economic and regulatory environment. Account balances are charged off against the allowance approximately 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 nine months ended June 30, 2023 and 2022 are as follows (in thousands):
Balance at Beginning of Period
Additions Charged to Costs and Expenses
Discounts on Purchased Receivables
Net Accounts Receivable Written-Off
Balance at End of Period
Nine Months Ended June 30, 2023
Allowance for Uncollectible Accounts
$
40,228
$
13,142
$
1,316
$
(11,578)
$
43,108
Nine Months Ended June 30, 2022
Allowance for Uncollectible Accounts
$
31,639
$
12,024
$
1,211
$
(2,891)
$
41,983
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 $86.5 million at June 30, 2023, is reduced to zero by September 30 of each year as the inventory is replenished.
Property, Plant and Equipment. In the Company’s Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. The Company's capitalized costs relating to oil and gas producing activities, net of accumulated depreciation, depletion and amortization, were $2.4 billion and $1.9 billion at June 30, 2023 and September 30, 2022, 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 $190.5 million and $66.0 million at June 30, 2023 and September 30, 2022, 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 June 30, 2023, the ceiling exceeded the book value of the oil and gas properties by approximately $1.8 billion. The estimated future net cash flows were decreased by $460.4 million for hedging under the ceiling test at June 30, 2023.
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 June 30, 2023.
Accumulated Other Comprehensive Loss. The components of Accumulated Other Comprehensive Loss and changes for the nine months ended June 30, 2023 and 2022, 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 June 30, 2023
Balance at April 1, 2023
$
(1,294)
$
(53,570)
$
(54,864)
Other Comprehensive Gains and Losses Before Reclassifications
47,359
—
47,359
Amounts Reclassified From Other Comprehensive Income
(41,879)
—
(41,879)
Balance at June 30, 2023
$
4,186
$
(53,570)
$
(49,384)
Nine Months Ended June 30, 2023
Balance at October 1, 2022
$
(572,163)
$
(53,570)
$
(625,733)
Other Comprehensive Gains and Losses Before Reclassifications
488,726
—
488,726
Amounts Reclassified From Other Comprehensive Income
87,623
—
87,623
Balance at June 30, 2023
$
4,186
$
(53,570)
$
(49,384)
Three Months Ended June 30, 2022
Balance at April 1, 2022
$
(584,812)
$
(69,442)
$
(654,254)
Other Comprehensive Gains and Losses Before Reclassifications
(145,322)
—
(145,322)
Amounts Reclassified From Other Comprehensive Loss
216,708
—
216,708
Balance at June 30, 2022
$
(513,426)
$
(69,442)
$
(582,868)
Nine Months Ended June 30, 2022
Balance at October 1, 2021
$
(449,962)
$
(63,635)
$
(513,597)
Other Comprehensive Gains and Losses Before Reclassifications
(492,841)
—
(492,841)
Amounts Reclassified From Other Comprehensive Loss
429,377
—
429,377
Other Post-Retirement Adjustment for Regulatory Proceeding
—
(5,807)
(5,807)
Balance at June 30, 2022
$
(513,426)
$
(69,442)
$
(582,868)
During the quarter ended March 31, 2022, the PaPUC concluded a regulatory proceeding that addressed the recovery of other post-employment benefit (“OPEB”) expenses in Distribution Corporation's Pennsylvania service territory. As a result of that proceeding, Distribution Corporation suspended regulatory accounting for OPEB expenses in Pennsylvania and a regulatory deferral of $7.4 million ($5.8 million after-tax) related to the funded status of Distribution Corporation’s other post-retirement benefit plans in Pennsylvania was reclassified to accumulated other comprehensive loss.
Reclassifications Outof Accumulated Other Comprehensive Loss. The details about the reclassification adjustments out of accumulated other comprehensive loss for the nine months ended June 30, 2023 and 2022 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 June 30,
Nine Months Ended June 30,
2023
2022
2023
2022
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
Commodity Contracts
$57,842
($298,372)
($120,088)
($591,271)
Operating Revenues
Foreign Currency Contracts
(150)
1
(502)
91
Operating Revenues
57,692
(298,371)
(120,590)
(591,180)
Total Before Income Tax
(15,813)
81,663
32,967
161,803
Income Tax Expense
$41,879
($216,708)
($87,623)
($429,377)
Net of Tax
Other Current Assets. The components of the Company’s Other Current Assets are as follows (in thousands):
At June 30, 2023
At September 30, 2022
Prepayments
$
24,060
$
17,757
Prepaid Property and Other Taxes
11,420
14,321
Prepaid State Income Taxes
5,804
5,933
Regulatory Assets
30,302
21,358
$
71,586
$
59,369
Other Accruals and Current Liabilities. The components of the Company’s Other Accruals and Current Liabilities are as follows (in thousands):
At June 30, 2023
At September 30, 2022
Accrued Capital Expenditures
$
51,078
$
64,720
Regulatory Liabilities
38,499
31,293
Reserve for Gas Replacement
86,509
—
Liability for Royalty and Working Interests
15,754
86,206
Non-Qualified Benefit Plan Liability
17,474
17,474
Other
51,583
57,634
$
260,897
$
257,327
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 restricted stock units and performance shares. For the quarter and nine months ended June 30, 2023, 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. Restricted stock units and performance shares that are antidilutive are excluded from the calculation of diluted earnings per common share. There were 8,322 securities and 4,526 securities excluded as being antidilutive for the quarter and nine months ended June 30, 2023, respectively. There were 873 securities and 6,990 securities excluded as being antidilutive for the quarter and nine months ended June 30, 2022, respectively.
Stock-Based Compensation. The Company granted 202,259 performance shares during the nine months ended June 30, 2023. The weighted average fair value of such performance shares was $64.28 per share for the nine months ended June 30, 2023. 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 nine months ended June 30, 2023 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 to the extent management achieves methane intensity and greenhouse gas reduction targets making progress towards the Company's 2030 goals. 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 125,673 restricted stock units during the nine months ended June 30, 2023. The weighted average fair value of such restricted stock units was $58.67 per share for the nine months ended June 30, 2023. 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 fair value at the date of grant of the restricted stock units (represented by the market value of Company common stock on the date of the award) must be reduced by the present value of forgone dividends over the vesting term of the award. The fair value of restricted stock units on the date of award is recorded as compensation expense over the vesting period.
On June 1, 2023, the Company completed its acquisition of certain upstream assets located primarily in Tioga County, Pennsylvania from SWN Production Company, LLC ("SWN") for total consideration of $124.8 million. The purchase price, which reflects an effective date of January 1, 2023, was reduced for production revenues less expenses that were retained by SWN from the effective date to the closing date. As part of the transaction, the Company acquired approximately 34,000 net acres in an area that is contiguous with existing Company-owned upstream assets. This transaction was accounted for as an asset acquisition, and, as such, the purchase price was allocated to property, plant and equipment. The following is a summary of the asset acquisition in thousands:
Purchase Price
$
124,178
Transaction Costs
580
Total Consideration
$
124,758
On June 30, 2022, the Company completed the sale of Seneca’s California assets, all of which were in the Exploration and Production segment, to Sentinel Peak Resources California LLC for a total sale price of $253.5 million, consisting of $240.9 million in cash and contingent consideration valued at $12.6 million at closing. The Company pursued this sale given the strong commodity price environment and the Company's strategic focus in the Appalachian Basin. Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed $10 million per year, with the amount of each annual payment calculated as $1.0 million for each $1 per barrel that the ICE Brent Average for each calendar year exceeds $95 per barrel up to $105 per barrel. The sale price, which reflected an effective date of April 1, 2022, was reduced for production revenues less expenses that were retained by Seneca from the effective date to the closing date. Under the full cost method of accounting for oil and natural gas properties, $220.7 million of the sale price at closing was accounted for as reduction of capitalized costs since the disposition did not alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center. The remainder of the sale price ($32.8 million) was applied against assets that are not subject to the full cost method of accounting, with the Company recognizing a gain of $12.7 million on the sale of such assets. The majority of this gain related to the sale of emission allowances. The Company also eliminated the asset retirement obligation associated with Seneca’s California oil and gas assets. This obligation amounted to $50.1 million and was accounted for as a reduction of capitalized costs under the full cost method of accounting.
The following tables provide a disaggregation of the Company's revenues for the quarter and nine months ended June 30, 2023 and 2022, presented by type of service from each reportable segment.
The Company records revenue related to its derivative financial instruments in the Exploration and Production segment. 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: $54.1 million for the remainder of fiscal 2023; $209.1 million for fiscal 2024; $182.3 million for fiscal 2025; $147.8 million for fiscal 2026; $123.9 million for fiscal 2027; and $694.3 million thereafter.
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 June 30, 2023 and September 30, 2022. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.
(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 June 30, 2023 and September 30, 2022 include natural gas price swap agreements, natural gas no cost collars, and foreign currency contracts, all of which are used in the Company’s Exploration and Production segment. Hedging collateral deposits of $91.7 million at September 30, 2022, which were associated with the price swap agreements, no cost collars and foreign currency contracts, have been reported in Level 1. The fair value of the Level 2 price swap agreements and no cost collars is based on an internal cash flow model that uses observable inputs (i.e. SOFR based discount rates for the price swap agreements 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 June 30, 2023, the Company determined that nonperformance risk associated with the price swap agreements, no cost collars and foreign currency contracts 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.
Derivative financial instruments reported in Level 2 at June 30, 2023 also includes the contingent consideration associated with the sale of the Exploration and Production segment's California assets on June 30, 2022, which is discussed at Note 2 – Asset Acquisitions and Divestitures and at Note 5 – Financial Instruments. The fair value of the contingent consideration was calculated using a Monte Carlo simulation model that uses observable inputs, including the ICE Brent closing price as of the valuation date, initial and max trigger price, volatility, risk free rate, time of maturity and counterparty risk.
For the quarters ended June 30, 2023 and June 30, 2022, 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):
June 30, 2023
September 30, 2022
Carrying Amount
Fair Value
Carrying Amount
Fair Value
Long-Term Debt
$
2,383,685
$
2,213,689
$
2,632,409
$
2,453,209
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 June 30, 2023
At September 30, 2022
Life Insurance Contracts
$
42,411
$
42,171
Equity Mutual Fund
16,504
19,506
Fixed Income Mutual Fund
15,862
33,348
$
74,777
$
95,025
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 collar and swap agreements to manage the price risk associated with forecasted sales of natural gas. 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 8 years.
On June 30, 2022, the Company completed the sale of Seneca’s California assets. Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed $10 million per year, with the amount of each annual payment calculated as $1.0 million for each $1 per barrel that the ICE Brent Average for each calendar year exceeds $95 per barrel up to $105 per barrel. The Company has determined that this contingent consideration meets the definition of a derivative under the authoritative accounting guidance. Changes in the fair value of this contingent consideration are marked-to-market each reporting period, with changes in fair value recognized in Other Income (Deductions) on the Consolidated Statement of Income. The fair value of this contingent consideration was estimated to be $4.5 million and $8.2 million at June 30, 2023 and September 30, 2022, respectively. A $1.4 million mark-to-market adjustment to reduce the fair value of the contingent consideration was recorded during the quarter ended June 30, 2023. A $3.7 million mark-to-market adjustment to reduce the fair value of the contingent consideration was recorded during the nine months ended June 30, 2023.
The Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at June 30, 2023 and September 30, 2022.
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 June 30, 2023, the Company had 457.7 Bcf of natural gas commodity derivative contracts (swaps and no cost collars) outstanding.
As of June 30, 2023, the Company was hedging a total of $53.4 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts.
As of June 30, 2023, the Company had $4.2 million of net hedging gains after taxes included in the accumulated other comprehensive income (loss) balance. It is expected that $21.6 million of unrealized gains after taxes 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 June 30, 2023 and 2022 (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 June 30,
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 June 30,
2023
2022
2023
2022
Commodity Contracts
$
64,653
$
(198,827)
Operating Revenue
$
57,842
$
(298,372)
Foreign Currency Contracts
591
(1,257)
Operating Revenue
(150)
1
Total
$
65,244
$
(200,084)
$
57,692
$
(298,371)
The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Nine Months Ended June 30, 2023 and 2022 (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 Nine Months Ended June 30,
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 Nine Months Ended June 30,
The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on a quarterly basis monitors counterparty credit exposure. The majority of the Company’s counterparties are financial institutions and energy traders. The Company has over-the-counter swap positions, no cost collars and applicable foreign currency forward contracts with eighteen counterparties of which nine are in a net gain position. On average, the Company had $4.6 million of credit exposure per counterparty in a gain position at June 30, 2023. The maximum credit exposure per counterparty in a gain position at June 30, 2023 was $16.1 million. As of June 30, 2023, no collateral was received from the counterparties by the Company. The Company's gain position on such derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral, nor had the counterparties' credit ratings declined to levels at which the counterparties were required to post collateral.
As of June 30, 2023, sixteen of the eighteen counterparties to the Company’s outstanding derivative financial 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 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 June 30, 2023, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $7.4 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 June 30, 2023. 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.
Note 6 – Income Taxes
The effective tax rates for the quarters ended June 30, 2023 and June 30, 2022 were 26.2% and 23.3%, respectively. The effective tax rates for the nine months ended June 30, 2023 and June 30, 2022 were 25.8% and 24.9%, respectively. During the quarter and nine months ended June 30, 2022, the Company was able to utilize the Enhanced Oil Recovery tax credit, which was not available during the quarter and nine months ended June 30, 2023 due to the sale of its California properties.
On April 14, 2023, the IRS issued guidance that provides a safe harbor method of accounting that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized. The Company is currently analyzing this guidance to determine the potential impact on the financial statements.
Dividends Declared on Common Stock ($0.495 Per Share)
(45,444)
Other Comprehensive Income, Net of Tax
5,480
Share-Based Payment Expense (1)
4,009
Common Stock Issued Under Stock and Benefit Plans
9
9
502
Balance at June 30, 2023
91,804
$
91,804
$
1,035,852
$
1,857,630
$
(49,384)
Balance at October 1, 2022
91,478
$
91,478
$
1,027,066
$
1,587,085
$
(625,733)
Net Income Available for Common Stock
403,189
Dividends Declared on Common Stock ($1.445 Per Share)
(132,644)
Other Comprehensive Income, Net of Tax
576,349
Share-Based Payment Expense (1)
14,327
Common Stock Issued (Repurchased) Under Stock and Benefit Plans
326
326
(5,541)
Balance at June 30, 2023
91,804
$
91,804
$
1,035,852
$
1,857,630
$
(49,384)
Balance at April 1, 2022
91,449
$
91,449
$
1,018,784
$
1,407,683
$
(654,254)
Net Income Available for Common Stock
108,158
Dividends Declared on Common Stock ($0.475 Per Share)
(43,446)
Other Comprehensive Income, Net of Tax
71,386
Share-Based Payment Expense (1)
4,094
Common Stock Issued Under Stock and Benefit Plans
17
17
76
Balance at June 30, 2022
91,466
$
91,466
$
1,022,954
$
1,472,395
$
(582,868)
Balance at October 1, 2021
91,182
$
91,182
$
1,017,446
$
1,191,175
$
(513,597)
Net Income Available for Common Stock
407,879
Dividends Declared on Common Stock ($1.385 Per Share)
(126,659)
Other Comprehensive Loss, Net of Tax
(69,271)
Share-Based Payment Expense (1)
13,826
Common Stock Issued (Repurchased) Under Stock and Benefit Plans
284
284
(8,318)
Balance at June 30, 2022
91,466
$
91,466
$
1,022,954
$
1,472,395
$
(582,868)
(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 nine months ended June 30, 2023, the Company issued 12,055 original issue shares of common stock as a result of SARs exercises, 113,566 original issue shares of common stock for restricted stock units that vested and 278,687 original issue shares of common stock for performance shares that vested. The Company also issued 22,685 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 (the "DCP") during the nine months ended June 30, 2023. In addition, the Company issued 1,735 original issue shares of common stock to officers of the Company who elected to defer their shares pursuant to the dividend reinvestment feature of the Company's DCP Plan during the nine months ended June 30, 2023. Holders
of stock-based compensation awards will often tender shares of common stock to the Company for payment of applicable withholding taxes. During the nine months ended June 30, 2023, 102,796 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.
Short-Term Borrowings. On June 30, 2022, the Company entered into a 364-Day Credit Agreement (the "364-Day Credit Agreement") with a syndicate of five banks, all of which are also lenders under the Credit Agreement (as amended from time to time, the "Credit Agreement"). The 364-Day Credit Agreement provided an additional $250.0 million unsecured committed delayed draw term loan credit facility with a maturity date of June 29, 2023. The Company elected to draw $250.0 million under the facility on October 27, 2022. The Company used the proceeds for general corporate purposes, which included using $150.0 million for the November 2022 redemption of a portion of the Company's outstanding long-term debt with a maturity date in March 2023. All indebtedness under the 364-Day Credit Agreement was repaid in May 2023 prior to its June 29, 2023 maturity date.
Current Portion of Long-Term Debt.None of the Company's long-term debt as of June 30, 2023 had a maturity date within the following twelve-month period. The Current Portion of Long-Term Debt at September 30, 2022 consisted of $500.0 million of 3.75% notes and $49.0 million of 7.395% notes. The Company redeemed $150.0 million of the 3.75% notes on November 25, 2022 using a portion of the proceeds from short-term borrowings, as discussed above. In March 2023, the Company redeemed the remaining $350.0 million of the 3.75% notes as well as the $49.0 million of 7.395% notes.
Long-Term Debt. On May 18, 2023, the Company issued $300.0 million of 5.50% notes due October 1, 2026. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $297.5 million. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade. Additionally, the interest rate payable on the notes will be subject to adjustment from time to time, with a maximum adjustment of 2.00%, such that the coupon will not exceed 7.50%, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to a rating below investment grade. A downgrade with a resulting increase to the coupon does not preclude the coupon from returning to its original rate if the Company's credit rating is subsequently upgraded. The proceeds of this debt issuance were used for general corporate purposes, including to repay all indebtedness under the $250.0 million unsecured committed delayed draw term loan under the 364-Day Credit Agreement, as discussed above.
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 June 30, 2023, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $3.6 million. The Company's liability for such clean-up costs has been recorded in Other Liabilities on the Consolidated Balance Sheet at June 30, 2023. The Company has recovered its environmental clean-up costs through rate recovery 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 June 29, 2022, received an extension of time from FERC, until December 31, 2024, to construct the project. As of June 30, 2023, the Company has spent approximately $55.8 million on the project, all of which is recorded on the balance sheet.
Other. The Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations and other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these other matters arising in the normal course of business could have a material effect on earnings and cash flows in the period in which they are resolved, an estimate of the possible loss or range of loss, if any, cannot be made at this time.
Note 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 2022 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 2022 Form 10-K. A listing of segment assets at June 30, 2023 and September 30, 2022 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 June 30,
2023
2022
2023
2022
Service Cost
$
1,297
$
2,190
$
147
$
332
Interest Cost
10,629
5,707
3,912
2,267
Expected Return on Plan Assets
(16,648)
(13,074)
(6,403)
(7,340)
Amortization of Prior Service Cost (Credit)
109
134
(107)
(107)
Amortization of (Gains) Losses
(1,920)
6,601
(2,189)
(1,903)
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)
5,378
3,470
3,829
5,351
Net Periodic Benefit Cost (Income)
$
(1,155)
$
5,028
$
(811)
$
(1,400)
Retirement Plan
Other Post-Retirement Benefits
Nine Months Ended June 30,
2023
2022
2023
2022
Service Cost
$
3,891
$
6,568
$
440
$
996
Interest Cost
31,887
17,121
11,736
6,800
Expected Return on Plan Assets
(49,945)
(39,221)
(19,210)
(22,020)
Amortization of Prior Service Cost (Credit)
327
403
(321)
(321)
Amortization of (Gains) Losses
(5,760)
19,803
(6,566)
(5,708)
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)
16,134
16,308
11,143
15,870
Net Periodic Benefit Cost (Income)
$
(3,466)
$
20,982
$
(2,778)
$
(4,383)
(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. The Company did not make any contributions to its tax-qualified, noncontributory defined benefit retirement plan (Retirement Plan) or its VEBA trusts for its other post-retirement benefits during the nine months ended June 30, 2023, and does not anticipate making any such contributions during the remainder of fiscal 2023.
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%, and directed the implementation of an earnings sharing mechanism to be in place beginning on April 1, 2018. The order also authorized the Company to recover approximately $15 million annually for pension and OPEB expenses from customers. Because the Company’s future pension and OPEB costs were projected to be satisfied with existing funds held in reserve, in July 2022, Distribution Corporation made a filing with the NYPSC to effectuate a pension and OPEB surcredit to customers to offset these amounts being collected in base rates effective October 1, 2022. On September 16, 2022, the NYPSC issued an order approving the filing. The surcredit will remain in effect until modified by the NYPSC in another proceeding, or until December 31, 2024, whichever is earlier. With the implementation of this surcredit, Distribution Corporation will no longer be funding the Retirement Plan or its VEBA trusts in its New York jurisdiction.
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). On December 9, 2022, the Company filed a petition with the NYPSC to effectuate a system improvement tracker through which qualified pipeline replacement costs through September 30, 2024 would be tracked and recovered, and to recover certain deferred costs associated with the existing system modernization tracker, effective April 1, 2023. The NYPSC approved the petition by order dated March 17, 2023 contingent on the Company not filing a base rate case that would result in new rates becoming effective prior to October 1, 2024.
On January 19, 2023, the NYPSC issued an order in its Effects of COVID-19 on Utility Service (20-M-0266) and Energy Affordability for Low Income Utility Customers (14-M-0565) proceedings whereby a Phase 2 Utility Arrears Relief Program was authorized. Specifically, the order directed Distribution Corporation and certain other New York utilities to, among other things, address arrears on residential non-energy affordability program (EAP) ratepayer accounts that did not receive a credit under the NYPSC’s Phase 1 program and small commercial ratepayer accounts by issuing a one-time bill credit to such customers to reduce or eliminate accrued arrears through May 1, 2022. The credits shall be processed within 90 days of the effective date of the order, provided that residential non-EAP customers who had their service disconnected for non-payment in 2022 shall be allowed the opportunity to have their service reinstated in order to receive the credit through June 30, 2023. The order further directs utilities to suspend residential service terminations for non-payment while arrears credits are applied to accounts through March 1, 2023, or 30 days after credits have been applied, whichever is later. The order authorizes the utilities to recover the Phase 2 costs (the arrears credits and associated carrying charges) through a surcharge. Utilities proposed various offsets to Phase 2 program costs, and Distribution Corporation has proposed certain offsets as part of an uncollectible expense reconciliation proposal. On February 17, 2023, Distribution Corporation made a filing with the NYPSC seeking approval of its uncollectible expense reconciliation mechanism. On July 19, 2023, the NYPSC noticed Distribution Corporation’s filing in the New York State Register indicating that public comment will be received on the filing until sixty days after publication or until September 18, 2023. Application of the proposed offsets and collection periods will be determined when the NYPSC rules on the uncollectible expense reconciliation filing.
Pennsylvania Jurisdiction
Distribution Corporation’s delivery rates effective through July 31, 2023 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. On October 28, 2022, Distribution Corporation made a filing with the PaPUC seeking an increase in its annual base rate operating revenues of $28.1 million with a proposed effective date of December 27, 2022. On December 8, 2022, the PaPUC issued an order suspending the filing until July 27, 2023 by operation of law unless directed otherwise by the PaPUC. Following discovery, the submission of testimony and an evidentiary hearing, the parties to the proceeding agreed to a settlement that authorizes, among other things, an increase in Distribution Corporation’s annual base rate operating revenues of $23 million as of August 1, 2023. On April 13, 2023, Distribution Corporation filed a joint petition with the PaPUC seeking approval of the settlement on behalf of all active parties to the proceeding. On June 15, 2023, the PaPUC issued an order granting the joint petition and adopting the settlement in full, without modification or correction.
Effective October 1, 2021, pursuant to a tariff supplement filed with the PaPUC, Distribution Corporation reduced base rates by $7.7 million in order to stop collecting OPEB expenses from customers. It also began to refund to customers overcollected OPEB expenses in the amount of $50.0 million. All matters with respect to this tariff supplement were finalized on February 24, 2022 with the PaPUC’s approval of an Administrative Law Judge’s Recommended Decision. Concurrent with
that decision, the Company discontinued regulatory accounting for OPEB expenses and recorded an $18.5 million adjustment during the quarter ended March 31, 2022 to reduce its regulatory liability for previously deferred OPEB income amounts through September 30, 2021 and to increase Other Income (Deductions) on the consolidated financial statements by a like amount. The Company also increased customer refunds of overcollected OPEB expenses from $50.0 million to $54.0 million. All refunds specified in the tariff supplement are being 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 is no longer funding the grantor trust or its VEBA trusts in its Pennsylvania jurisdiction.
FERC Jurisdiction
Supply Corporation filed a NGA Section 4 rate case at FERC on July 31, 2023 proposing rate increases to be effective February 1, 2024. The proposed rates reflect an annual cost of service of $385.4 million, a rate base of $1.32 billion and a proposed cost of equity of 15.12%. If the proposed rate increases finally approved at the end of the proceeding exceed the rates that were in effect at July 31, 2023, but are less than rates put into effect subject to refund on February 1, 2024, Supply Corporation would be required to refund the difference between the rates collected subject to refund and the final approved rates, with interest at the FERC-approved rate. If the rates approved at the end of the proceeding are lower than the rates in effect at July 31, 2023, such lower rates will become effective prospectively from the effective date provided by the applicable FERC order, and refunds with interest will be limited to the difference between the rates collected subject to refund and the rates in effect at July 31, 2023.
Empire’s 2019 rate settlement provides that Empire must make a rate case filing no later than May 1, 2025.
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
OVERVIEW
Please note that this overview is a high-level summary of items that are discussed in greater detail in subsequent sections of this report.
The Company is a diversified energy company engaged principally in the production, gathering, transportation, storage 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 reports financial results for four business segments. For a discussion of the Company's earnings, refer to the Results of Operations section below.
On June 1, 2023, the Company completed its acquisition of certain upstream assets located primarily in Tioga County, Pennsylvania from SWN Production Company, LLC ("SWN") for total consideration of $124.8 million. As part of the transaction, the Company acquired approximately 34,000 net acres in an area that is contiguous with existing Company-owned upstream assets. This transaction was accounted for as an asset acquisition and, as such, the purchase price was allocated to property, plant and equipment.
On June 30, 2022, the Company completed the sale of Seneca’s California assets to Sentinel Peak Resources California LLC for a total sale price of $253.5 million, consisting of $240.9 million in cash and contingent consideration valued at $12.6 million at closing. The Company pursued this sale given the strong commodity price environment and the Company's strategic focus in the Appalachian Basin. Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed $10 million per year, with the amount of each annual payment calculated as $1.0 million for each $1 per barrel that the ICE Brent Average for each calendar year exceeds $95 per barrel up to $105 per barrel. The sale price, which reflected an effective date of April 1, 2022, was reduced for production revenues less expenses that were retained by Seneca from the effective date to the closing date. Under the full cost method of accounting for oil and natural gas properties, $220.7 million of the sale price at closing was accounted for as a reduction of capitalized costs since the disposition did not alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center. The remainder of the sale price ($32.8 million) was applied
against assets that are not subject to the full cost method of accounting, with the Company recognizing a gain of $12.7 million on the sale of such assets. The majority of this gain related to the sale of emission allowances.
From a rate perspective, Distribution Corporation, in its Pennsylvania jurisdiction, reached a settlement with the parties to its rate case proceeding. On June 15, 2023, the PaPUC issued an order adopting the settlement in full. The settlement authorizes an increase in Distribution Corporation's annual base rate operating revenues of $23 million effective August 1, 2023. In addition, Supply Corporation filed a NGA Section 4 rate case at FERC on July 31, 2023. For further discussion of Distribution Corporation and Supply Corporation rate matters, refer to the Rate Matters section below.
From a financing perspective, on June 30, 2022, the Company entered into a 364-Day Credit Agreement (the "364-Day Credit Agreement") with a syndicate of five banks, all of which are also lenders under the Credit Agreement. The 364-Day Credit Agreement provided an additional $250.0 million unsecured committed delayed draw term loan credit facility with a maturity date of June 29, 2023. The Company elected to draw $250.0 million under the facility on October 27, 2022. The Company used the proceeds for general corporate purposes, which included using $150.0 million for the November 2022 redemption of a portion of the Company's outstanding long-term debt with a maturity date in March 2023. In March 2023, the Company utilized short-term borrowings and cash on hand to redeem the remaining long-term debt that had maturity dates in March 2023, which included $350.0 million of 3.75% notes and $49.0 million of 7.395% notes.
On May 18, 2023, the Company issued $300.0 million of 5.50% notes due October 1, 2026.The proceeds of this debt issuance were used for general corporate purposes, including to repay all indebtedness under the $250.0 million unsecured committed delayed draw term loan under the 364-Day Credit Agreement mentioned above.
The Company expects to use cash on hand, cash from operations, and short-term borrowings, as needed, to meet its financing needs for the remainder of fiscal 2023. The Company continues to evaluate these financing needs and options to meet them. Given the current economic conditions, which include continued inflationary pressures and rising interest rates, the cost and/or availability of capital may be impacted, but the Company continues to expect to meet its financing needs as discussed above.
In early 2023, turmoil with certain financial institutions created uncertainty in the economy. While the Company was not directly impacted, it continues to closely monitor any potential future impacts on the business. The Company has a diverse group of twelve banks that participate in its multi-year credit facility. All of these banks have solid investment grade credit ratings. Additionally, the Company regularly reviews the credit quality of its hedging counterparties, those that provide credit support for customers, and any other material counterparties, and has not identified any material risks as a result of the current economic uncertainty.
CRITICAL ACCOUNTING ESTIMATES
For a complete discussion of critical accounting estimates, refer to "Critical Accounting Estimates" in Item 7 of the Company's 2022 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, with natural gas properties in the Appalachian Region being the primary component after the June 30, 2022 sale of the Company's California oil and natural gas properties. That sale is discussed in more detail in Item 1 at Note 2 - Asset Acquisitions and Divestitures. In accordance with the full cost 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 June 30, 2023, the ceiling exceeded the book value of the oil and gas properties by approximately $1.8 billion. The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended June 30, 2023, based on the quoted Henry Hub spot price for natural gas, was $4.76 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 Henry Hub price, which is only indicative of 12-month average prices for the twelve months ended June 30, 2023. Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.) In
regard to the sensitivity of the ceiling test calculation to commodity price changes, if natural gas prices were $0.25 per MMBtu lower than the average prices used at June 30, 2023 in the ceiling test calculation, the ceiling would have exceeded the book value of the Company's oil and gas properties by approximately $1.5 billion (after-tax), which would not have resulted in an impairment charge. This calculated amount is based solely on price changes and does not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates.
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 natural 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 2022 Form 10-K.
RESULTS OF OPERATIONS
Earnings
The Company's earnings were $92.6 million for the quarter ended June 30, 2023 compared to earnings of $108.2 million for the quarter ended June 30, 2022. The decrease in earnings of $15.6 million is primarily the result of lower earnings in all reportable segments, as well as a loss in the All Other category. Higher earnings in the Corporate category partially offset these decreases.
The Company's earnings were $403.2 million for the nine months ended June 30, 2023 compared to earnings of $407.9 million for the nine months ended June 30, 2022. The decrease in earnings of $4.7 million is primarily the result of lower earnings in the Utility segment and Pipeline and Storage segment, as well as a loss in the All Other category. Higher earnings in the Exploration and Production segment, Gathering segment and Corporate category partially offset these decreases.
The Company's earnings for the quarter and nine months ended June 30, 2022 included the impact of several items in the Company's Exploration and Production segment related to the completion of the sale of Seneca’s California assets, as discussed above. The Company recorded a gain on the sale of these assets of $12.7 million ($9.5 million after-tax) related to a portion of the sales price that was applied to assets that were not subject to the full cost method of accounting. The Company also recorded a loss of $44.6 million ($33.3 million after-tax) related to the termination of its remaining crude oil derivative contracts as a result of the sale. In addition, the Company incurred transaction and severance costs of $9.7 million ($7.2 million after-tax) related to the California asset sale. The Company's earnings for the nine months ended June 30, 2022 also included the reduction of an OPEB regulatory liability that increased earnings by $18.5 million ($14.6 million after-tax) recorded during the quarter ended March 31, 2022 in the Utility segment in accordance with a regulatory proceeding in Distribution Corporation's Pennsylvania service territory. 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 earnings discussions are after-tax amounts, unless otherwise noted.
(1) Oil revenue and weighted average oil price after hedging for the three months and nine months ended June 30, 2022 excludes a loss on discontinuance of crude oil cash flow hedges of $44.6 million. This loss is presented in other revenue in the table above.
N/M - Not Meaningful (as a result of the sale of Seneca's West Coast assets in June 2022)
Operating revenues for the Exploration and Production segment decreased $36.1 million for the quarter ended June 30, 2023 as compared with the quarter ended June 30, 2022. Gas production revenue after hedging decreased $40.9 million due to the impact of a $0.60 per Mcf decrease in the weighted average price of natural gas after hedging, offset by a 5.5 Bcf increase in natural gas production. Natural gas production increased largely due to additional production from new Marcellus and Utica wells in the Appalachian region. Oil production revenue after hedging decreased $40.4 million due to the sale of the Exploration and Production segment's California assets on June 30, 2022. In addition, other revenue increased $45.9 million and gas processing plant revenue decreased $0.7 million. The increase in other revenue is primarily attributable to a loss on discontinuance of crude oil cash flow hedges as a result of the sale of the California assets combined with royalty shut-in payments made in accordance with lease agreements, both occurring in the quarter ended June 30, 2022. The decrease in gas processing plant revenue was mainly attributable to the sale of the California assets.
Operating revenues for the Exploration and Production segment decreased $20.3 million for the nine months ended June 30, 2023 as compared with the nine months ended June 30, 2022. Gas production revenue after hedging increased $49.1 million due to the impact of a 23.5 Bcf increase in natural gas production offset by a $0.05 per Mcf decrease in the weighted average price of natural gas after hedging. The increase in natural gas production was largely due to additional production from new Marcellus and Utica wells in the Appalachian region during the nine months ended June 30, 2023 as compared with the nine months ended June 30, 2022. Oil production revenue after hedging decreased $111.3 million due to the sale of the California assets. In addition, gas processing plant revenue decreased $2.2 million as a result of the sale of the California assets. Other revenue increased $44.1 million primarily attributable to a loss on discontinuance of crude oil cash flow hedges combined with royalty shut-in payments made in accordance with lease agreements, both occurring in the quarter ended June 30, 2022. These were partially offset by decreases due to higher temporary capacity releases during the nine months ended June 30, 2022 when compared to the nine months ended June 30, 2023 and a decrease in operating revenue from this segment's water treatment plants.
The Exploration and Production segment's earnings for the quarter ended June 30, 2023 were $43.3 million, a decrease of $13.2 million when compared with earnings of $56.5 million for the quarter ended June 30, 2022. The decrease in earnings was attributable to lower natural gas prices after hedging ($44.6 million), lower oil production ($31.9 million), higher depletion expense ($4.3 million) and an unrealized loss on contingent consideration received as part of the California asset sale ($1.0 million). These decreases were partially offset by higher natural gas production ($12.4 million), lower lease operating and transportation expenses ($14.0 million), lower other operating expenses ($6.1 million), lower other taxes ($3.8 million), a decrease in interest expense ($0.8 million) and higher other income ($0.5 million). Finally, in the quarter ended June 30, 2022, the Company also had a loss related to discontinuance of its crude oil cash flow hedges ($33.3 million) and had transaction and severance costs ($7.2 million), offset by a gain that was recognized on the sale of Seneca's California non-full cost pool assets ($9.5 million), all of which were driven by the sale of its California assets. The increase in depletion expense was primarily due to the net increase in production combined with a $0.04 per Mcf increase in the depletion rate. The decrease in lease operating and transportation expenses was primarily the result of the sale of the California assets, partially offset by higher gathering and transportation costs combined with higher lease operating expenses in the Appalachian region. The decrease in other operating expenses was primarily attributable to the California asset sale and recognizing abandonment costs related to certain offshore Gulf of Mexico wells that were formerly owned by Seneca, both occurring in the quarter ended June 30, 2022. The decrease in other taxes was primarily attributable to both the impact of the sale of Seneca's California assets as well as lower Impact Fees in the Appalachian region. The decrease in interest expense can largely be attributed to lower interest on intercompany long-term borrowings as a result of the Company's redemption of $500.0 million of 3.75% notes that was redeemed in March 2023, partially offset by additional interest on intercompany long-term borrowings related to the Company’s May 2023 debt issuance of $300.0 million of 5.50% notes and a higher average interest rate on intercompany short-term borrowings. The increase in other income was attributable to higher interest income, as well as non-service pension and post-retirement benefit income in the quarter ended June 30, 2023 compared to non-service pension and post-retirement benefit costs in the quarter ended June 30, 2022.
The Exploration and Production segment's earnings for the nine months ended June 30, 2023 were $195.5 million, an increase of $5.5 million when compared with earnings of $190.0 million for the nine months ended June 30, 2022. The increase in earnings was primarily attributable to higher natural gas production ($49.6 million), as discussed above, combined with lower lease operating and transportation expenses ($25.3 million), lower other operating expenses ($12.6 million), lower other taxes ($4.7 million), and higher other income ($2.8 million). Also, in the nine months ended June 30, 2022, the Company had a loss related to discontinuance of its crude oil cash flow hedges ($33.3 million) and had transaction and severance costs ($7.2 million), offset by a gain that was recognized on the sale of Seneca's California non-full cost pool assets ($9.5 million), all of which were driven by the sale of its California assets. Partially offsetting these items, the Exploration and Production
segment experienced lower natural gas prices after hedging ($10.8 million), lower oil production ($88.0 million), lower other revenue ($0.5 million) and lower gas processing plant revenue ($1.7 million), all of which are discussed above. Other factors that decreased earnings included higher depletion expense ($15.5 million), higher income tax expense ($1.8 million) and an unrealized loss on contingent consideration received as part of the California asset sale ($2.7 million). The decrease in lease operating and transportation expenses was primarily the result of the sale of the California assets, partially offset by higher gathering and transportation costs combined with higher lease operating expenses in the Appalachian region. The decrease in other operating expenses was primarily attributable to the California asset sale and recognizing abandonment costs related to certain offshore Gulf of Mexico wells that were formerly owned by Seneca, both occurring in nine months ended June 30, 2022. The decrease in other taxes was attributable to the impact of the California asset sale, combined with lower Impact Fees in the Appalachian region. The increase in other income was attributable to higher interest income, as well as non-service pension and post-retirement income in the nine months ended June 30, 2023 compared to non-service pension and post-retirement benefit costs in the nine months ended June 30, 2022. The increase in depletion expense was primarily due to the net increase in production combined with a $0.04 per Mcf increase in the depletion rate. The increase in income tax expense was primarily driven by a prior-year benefit realized from the Enhanced Oil Recovery tax credit, which did not recur in the current year as a result of the sale of the California assets.
Pipeline and Storage
Pipeline and Storage Operating Revenues
Three Months Ended June 30,
Nine Months Ended June 30,
(Thousands)
2023
2022
Increase (Decrease)
2023
2022
Increase (Decrease)
Firm Transportation
$
70,296
$
74,384
$
(4,088)
$
219,240
$
212,468
$
6,772
Interruptible Transportation
128
442
(314)
1,180
1,298
(118)
70,424
74,826
(4,402)
220,420
213,766
6,654
Firm Storage Service
21,147
21,084
63
63,901
63,334
567
Interruptible Storage Service
—
—
—
2
—
2
Other
824
(362)
1,186
831
2,195
(1,364)
$
92,395
$
95,548
$
(3,153)
$
285,154
$
279,295
$
5,859
Pipeline and Storage Throughput
Three Months Ended June 30,
Nine Months Ended June 30,
(MMcf)
2023
2022
Increase (Decrease)
2023
2022
Increase (Decrease)
Firm Transportation
181,440
175,868
5,572
637,145
601,491
35,654
Interruptible Transportation
97
206
(109)
2,024
1,726
298
181,537
176,074
5,463
639,169
603,217
35,952
2023 Compared with 2022
Operating revenues for the Pipeline and Storage segment decreased $3.2 million for the quarter ended June 30, 2023 as compared with the quarter ended June 30, 2022. The decrease in operating revenues was primarily due to a decrease in transportation revenues of $4.4 million, partially offset by an increase in other revenues of $1.2 million. The decrease in transportation revenues is primarily due to contract expirations, partially offset by an increase in new short-term contracts. The increase in other revenues primarily reflects an adjustment to electric surcharge revenues and higher cashout revenues. All customer surcharges and related adjustments for the electric surcharge mechanism are completely offset by an equal amount of electric power costs recorded in operation and maintenance expense. Cashout revenues are completely offset by purchased gas expense.
Operating revenues for the Pipeline and Storage segment increased $5.9 million for the nine months ended June 30, 2023 as compared with the nine months ended June 30, 2022. The increase in operating revenues was primarily due to an increase in transportation revenues of $6.7 million and an increase in storage revenues of $0.6 million, partially offset by a decrease in other revenues of $1.4 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. The increase from the FM100 Project includes the impact of a negotiated revenue step-up to Period 2 Rates that went into effect April 1, 2022, as specified in Supply Corporation's 2020 rate case settlement. An increase in short-term contracts also contributed to the increase in transportation revenues. These increases were partially offset by a decline in revenues associated with certain contract expirations and revisions. The increase in storage revenues was mainly due to the Period 2 Rates that went into effect April 1, 2022 related to the FM100 Project, as discussed above, as well as an increase in reservation charges for storage service from several new contracts that went into effect. The decrease in other revenues primarily reflects an adjustment to electric surcharge revenues and lower cashout revenues.
Transportation volume for the quarter ended June 30, 2023 increased by 5.5 Bcf from the prior year's quarter ended June 30, 2022. For the nine months ended June 30, 2023, transportation volume increased by 36.0 Bcf from the prior year's nine-month period ended June 30, 2022. The increase in transportation volume for the quarter ended June 30, 2023 is primarily due to an increase in volume from various short-term contracts, partially offset by a decrease in volume from certain contract expirations. The increase in transportation volume for the nine-month period primarily reflects an increase in short-term contracts, as well as an increase in volume from the FM100 Project, which was brought online in December 2021. These were partially offset by certain contract expirations during the nine months ended June 30, 2023. 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 June 30, 2023 were $23.8 million, a decrease of $2.8 million when compared with earnings of $26.6 million for the quarter ended June 30, 2022. The decrease in earnings was primarily due to the earnings impact of lower operating revenues of $2.5 million, as discussed above, combined with an increase in operating expenses of $1.2 million and an increase in depreciation expense of $0.3 million. The increase in operating expenses was primarily due to higher personnel costs, higher pipeline integrity costs and an increase in compressor maintenance costs. The increase in depreciation expense was primarily due to new modernization projects going into service since the prior-year third quarter. These earnings decreases were partially offset by an increase in other income of $1.3 million, which was primarily due to a higher weighted average interest rate on intercompany short-term notes receivables along with higher non-service pension and post-retirement benefit income.
The Pipeline and Storage segment’s earnings for the nine months ended June 30, 2023 were $77.1 million, a decrease of $0.1 million when compared with earnings of $77.2 million for the nine months ended June 30, 2022. The decrease in earnings was primarily due to an increase in operating expenses ($4.9 million), an increase in depreciation expense ($1.9 million) and an increase in interest expense ($0.9 million). The increase in operating expenses was primarily due to higher personnel costs, higher pipeline integrity costs and an increase in compressor maintenance costs. This was partially offset by lower power costs related to Empire's electric motor drive compressor station. This reduction in electric power costs is offset by an equal reduction in revenue, as discussed above. The increase in depreciation expense was primarily due to incremental depreciation from the FM100 Project going into service in December 2021. The increase in interest expense was mainly due to an increase in intercompany short-term borrowings, partially offset by a decrease in interest on intercompany long-term borrowings primarily due to the Company's redemption of $500.0 million of 3.75% notes during the nine months ended June 30, 2023. These earnings decreases were partially offset by the earnings impact of higher operating revenues of $4.6 million, as discussed above, combined with an increase in other income ($2.8 million). The increase in other income is primarily due to a higher weighted average interest rate on intercompany short-term notes receivables along with higher non-service pension and post-retirement benefit income. This was partially offset by a decrease in allowance for funds used during construction (equity component) related to the construction of the FM100 Project that was placed into service in December 2021 along with an annual adjustment that was recorded during the current fiscal year.
Operating revenues for the Gathering segment increased $3.0 million for the quarter ended June 30, 2023 as compared with the quarter ended June 30, 2022, which was driven primarily by an 8.9 Bcf increase in gathered volume. Gathered volume on the Wellsboro, Trout Run, Covington and Clermont gathering systems increased 5.0 Bcf, 2.9 Bcf, 0.6 Bcf and 0.4 Bcf, respectively. The increase can be attributed to an increase in gross natural gas production in the Appalachian region by producers connected to the aforementioned gathering systems.
Operating revenues for the Gathering segment increased $11.5 million for the nine months ended June 30, 2023 as compared with the nine months ended June 30, 2022, which was driven primarily by a 21.5 Bcf increase in gathered volume. Contributors to the increase included the Covington and Clermont gathering systems, which recorded increases of 31.8 Bcf and 6.2 Bcf, respectively, partially offset by the Trout Run and Wellsboro gathering systems, which recorded decreases of 15.7 Bcf and 0.8 Bcf, respectively. The net increase can be attributed to an increase in gross natural gas production in the Appalachian region by producers connected to the aforementioned gathering systems.
The Gathering segment’s earnings for the quarter ended June 30, 2023 were $24.1 million, a decrease of $0.6 million when compared with earnings of $24.7 million for the quarter ended June 30, 2022. The decrease in earnings reflects higher operating expenses ($2.4 million), higher income tax expense ($0.6 million) and higher depreciation expense ($0.3 million), partially offset by higher gathering revenues ($2.4 million) and lower interest expense ($0.4 million). The increase in operating expenses was largely attributable to higher outside service costs associated with preventative maintenance overhauls as well as higher leased compression expense. The increase in gathering revenues was driven by the increase in gathered volume, as discussed above.
The Gathering segment’s earnings for the nine months ended June 30, 2023 were $73.2 million, an increase of $3.3 million when compared with earnings of $69.9 million for the nine months ended June 30, 2022. The increase in earnings was mainly due to higher gathering revenues ($9.1 million) driven by the increase in gathered volume, as discussed above, coupled with lower interest expense ($0.7 million) and lower other deductions ($0.5 million). These increases were partially offset by higher operating expenses ($4.5 million), higher income tax expense ($1.4 million) and higher depreciation expense ($1.0 million). The increase in operating expenses was largely attributable to higher outside service costs associated with preventative maintenance overhauls, higher leased compression expense, higher personnel costs and higher material costs. The increase in income tax expense was primarily driven by a higher effective state income tax rate. The increase in depreciation expense was largely due to higher plant balances associated with the Covington and Clermont gathering systems.
(1)Percents compare actual 2023 degree days to normal degree days and actual 2023 degree days to actual 2022 degree days.
2023 Compared with 2022
Operating revenues for the Utility segment decreased $35.3 million for the quarter ended June 30, 2023 as compared with the quarter ended June 30, 2022. The decrease resulted largely from a $33.4 million decrease in retail gas sales revenue and a $2.1 million decrease in transportation revenue. These decreases reflect a decrease in the cost of gas sold (per Mcf) (mostly for retail sales), a decrease in throughput, and a decrease in base rates. It should be noted that under its purchased gas adjustment clauses in New York and Pennsylvania, Distribution Corporation's earnings are not impacted by fluctuations in gas costs. Purchased gas expense recorded on the consolidated income statement matches the revenues collected from customers. The decrease in base rates is related to a tariff filing approved by the NYPSC, which created a surcredit that temporarily eliminates pension and OPEB cost recovery from base rates effective October 1, 2022. Additional details related to the regulatory proceeding are discussed in the Rate Matters section and in Item 1 at Note 11 - Regulatory Matters. The decreases in retail gas sales revenue and transportation revenue were partially offset by an increase in revenues earned under the system modernization and system improvement tracker mechanisms in Distribution Corporation's New York jurisdiction, which allow for the recovery of investments in leak prone pipe replacement. These decreases were partially offset by a $0.2 million increase in other revenues consisting of higher capacity release revenues ($0.2 million) and a smaller estimated refund provision from the income tax benefits resulting from the 2017 Tax Reform Act ($0.2 million). These increases in other revenues were reduced by lower late payment charges billed to customers ($0.3 million).
Operating revenues for the Utility segment increased $77.5 million for the nine months ended June 30, 2023 as compared with the nine months ended June 30, 2022. The increase largely resulted from an $80.1 million increase in retail gas sales revenue and a $4.2 million increase in other revenues, which were partially offset by a $6.8 million decrease in transportation revenue. The increase in retail gas sales revenue was primarily due to an increase in the cost of gas sold (per Mcf), partially offset by a decrease in base rates, as a result of the NYPSC tariff filing related to pension and OPEB costs discussed above, as well as a 2.4 Bcf decrease in throughput due to warmer weather during the winter months. Revenues collected in 2023 reflect not only the current cost of gas but also the collection of previously deferred undercollected gas costs. The increase in other revenues was largely due to higher capacity release revenues ($2.0 million), a smaller estimated refund provision from the income tax benefits resulting from the 2017 Tax Reform Act ($1.1 million), and a positive regulatory adjustment ($0.9 million). The decrease in transportation revenue was largely due to a 2.7 Bcf decrease in transportation
throughput due to warmer weather in the winter months and the decrease in base rates, as previously mentioned. The decrease in transportation revenue was partially offset by an increase in revenues earned under the system modernization and system improvement tracker mechanisms in Distribution Corporation's New York jurisdiction.
The Utility segment’s earnings for the quarter ended June 30, 2023 were less than $0.1 million compared to earnings of $4.6 million for the quarter ended June 30, 2022. The decrease was primarily due to higher operating expenses ($3.1 million), higher interest expense ($2.2 million), and higher income tax expense ($0.9 million). The increase in operating expenses was mainly due to higher personnel costs and outside services. The increase in interest expense was largely the result of a higher weighted average interest rate on intercompany short-term borrowings. Partially offsetting these decreases, the Utility segment's earnings benefited from the impact of the system modernization and system improvement trackers in New York ($0.9 million) and interest earned on deferred gas costs ($0.7 million).
The earnings impact of the reduction in the New York jurisdiction's base rates for the quarter ended June 30, 2023 resulting from the NYPSC tariff filing related to pension and OPEB costs discussed above ($2.0 million) was offset by a decrease in non-service pension and OPEB costs ($2.9 million). With the elimination of pension and OPEB expenses in customer rates, Distribution Corporation’s New York service territory did not recognize any pension and OPEB expenses during the quarter ended June 30, 2023, compared to the prior year period when it recognized pension and OPEB expenses to match against the pension and OPEB amounts collected in base rates.
Lastly, there was a decrease in the Utility's Pennsylvania service territory OPEB income ($0.5 million) related to a regulatory proceeding that concluded during the quarter ended March 31, 2022, as discussed below.
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 both the quarters ended June 30, 2023 and June 30, 2022, the WNC increased earnings by approximately $0.6 million, as the weather was warmer than normal.
The Utility segment’s earnings for the nine months ended June 30, 2023 were $55.6 million, a decrease of $24.2 million when compared with earnings of $79.8 million for the nine months ended June 30, 2022. The decrease in earnings was primarily attributable to the impact of a proceeding in the Utility's Pennsylvania service territory during the quarter ended March 31, 2022 that allowed for a favorable one-time adjustment of $14.6 million to recognize the cumulative amount of OPEB income, previously deferred as a regulatory liability in that jurisdiction, which did not recur in the nine months ended June 30, 2023. In addition to the non-recurrence of this transaction, there was a decrease in OPEB income ($2.2 million) in the Utility's Pennsylvania service territory. The earnings impact of the reduction in the New York jurisdiction's base rates for the nine months ended June 30, 2023 resulting from the NYPSC tariff filing discussed above ($11.1 million) was offset by a decrease in non-service pension and OPEB costs ($13.2 million).
Other factors that contributed to the earnings decrease in the Utility segment included higher interest expense ($7.6 million), primarily due to a higher weighted average interest rate on intercompany short-term borrowings, and higher operating expenses ($7.2 million), resulting from higher personnel costs and outside services. Factors that partially offset the earnings decrease in the Utility segment included the positive impact of a system modernization and system improvement tracker in New York ($3.5 million), interest earned on deferred gas costs ($1.9 million), and higher other operating revenues ($1.7 million). Other operating revenues increased largely due to higher capacity release revenues, a smaller estimated refund provision from the income tax benefits resulting from the 2017 Tax Reform Act, and a positive regulatory adjustment.
For both the nine months ended June 30, 2023 and June 30, 2022, the WNC increased earnings by approximately $4.8 million, as the weather was warmer than normal.
Corporate and All Other
2023 Compared with 2022
Corporate and All Other operations had earnings of $1.3 million for the quarter ended June 30, 2023, an increase of $5.5 million when compared with a net loss of $4.2 million for the quarter ended June 30, 2022. The increase was primarily attributable to changes in unrealized gains and losses on investments in equity securities. During the quarter ended June 30, 2023, the Company recorded unrealized gains of $0.3 million. During the quarter ended June 30, 2022, the Company recorded
unrealized losses of $2.7 million. Also contributing to the increase in earnings were changes in the cash surrender value of life insurance policies ($1.1 million) and lower non-service pension and post-retirement benefit costs ($0.5 million).
For the nine months ended June 30, 2023, Corporate and All Other operations had earnings of $1.8 million, an increase of $10.8 million when compared with a net loss of $9.0 million for the nine months ended June 30, 2022. The increase in earnings was primarily attributable to changes in unrealized gains and losses on investments in equity securities. During the nine months ended June 30, 2023, the Company recorded unrealized gains of $1.3 million. During the nine months ended June 30, 2022, the Company recorded unrealized losses of $8.0 million. Also contributing to the increase in earnings were changes in the cash surrender value of life insurance policies ($1.3 million) and lower non-service pension and post-retirement benefit costs ($1.6 million). These changes were partially offset by a decrease in realized gains from sales of investments in equity securities ($2.9 million).
Other Income (Deductions)
Net other income on the Consolidated Statements of Income was $3.6 million for the quarter ended June 30, 2023, compared to net other deductions of $5.6 million for the quarter ended June 30, 2022. This variation can be attributed primarily to the quarter-over-quarter change in non-service pension and post-retirement benefit income/expense. The Company recorded $1.4 million of non-service pension and post-retirement benefit income during the quarter ended June 30, 2023. During the quarter ended June 30, 2022, the Company recorded $3.2 million of non-service pension and post-retirement benefit expense. Changes in unrealized gains and losses on investments in equity securities also increased other income by $4.1 million, along with an increase in life insurance income of $1.1 million, period over period. Higher interest income of $1.1 million also contributed to the increase. This was primarily due to increased interest on a larger undercollection of gas costs quarter over quarter in Distribution Corporation. These increases were partially offset by a mark-to-market adjustment that reduced the value of the contingent consideration received from the sale of Seneca's California assets in June 2022 of $1.4 million.
Net other income on the Consolidated Statements of Income was $12.8 million for the nine months ended June 30, 2023, compared to net other income of $3.3 million for the nine months ended June 30, 2022. This was mostly due to changes in unrealized and realized gains and losses on investments in equity securities of $9.2 million, along with an increase in life insurance income of $1.3 million. Higher interest income of $5.6 million also contributed to the increase. This was primarily due to an increase in interest on temporary cash investments, increased interest on a larger undercollection of gas costs over the prior year in Distribution Corporation and an increase in interest income earned on investments. Offsetting these increases were a mark-to-market adjustment that reduced the value of the contingent consideration received from the sale of Seneca's California assets in June 2022 by $3.7 million and a $2.1 million reduction in allowance for funds used during construction. Also, there was a $0.5 million reduction in non-service pension and post-retirement benefit income year over year.
Interest Expense on Long-Term Debt
Interest expense on long-term debt on the Consolidated Statement of Income decreased $3.8 million for the quarter ended June 30, 2023 as compared to the quarter ended June 30, 2022. For the nine months ended June 30, 2023, interest expense on long-term debt decreased $6.8 million as compared with the nine months ended June 30, 2022. This was primarily due to the March 2023 redemptions of $350.0 million of the $500.0 million 3.75% notes and the $49.0 million 7.395% notes. In addition, $150.0 million of the $500.0 million 3.75% notes was redeemed in November 2022, which also contributed to the decrease. These redemptions were partially offset by the issuance of $300.0 million 5.50% notes in May 2023.
CAPITAL RESOURCES AND LIQUIDITY
The Company’s primary sources of cash during the nine-month period ended June 30, 2023 consisted of cash provided by operating activities, net proceeds from short-term and long-term borrowings and proceeds from the sale of a fixed income mutual fund held in a grantor trust. The Company’s primary sources of cash during the nine-month period ended June 30, 2022 consisted of cash provided by operating activities, net proceeds from short-term borrowings, proceeds from the sale of a fixed income mutual fund held in a grantor trust and net proceeds from the sale of oil and gas properties.
The Company expects to have adequate amounts of cash available to meet both its short-term and long-term cash requirements for at least the next twelve months and for the foreseeable future thereafter. During the remainder of 2023, cash provided by operating activities is expected to increase when compared to the same period in 2022 and will be used to fund the Company's capital expenditures. Cash provided by operating activities is expected to exceed capital expenditures in 2024. These cash flow projections do not reflect the impact of acquisitions or divestitures that may arise in the future.
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, 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 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 $1,055.1 million for the nine months ended June 30, 2023, an increase of $401.1 million compared with $654.0 million provided by operating activities for the nine months ended June 30, 2022. The increase in cash provided by operating activities primarily reflects higher cash provided by operating activities in the Exploration and Production segment and Utility segment. The increase in the Exploration and Production segment is primarily due to higher cash receipts from natural gas production. The increase in the Utility segment is primarily due to the timing of gas cost recovery and the timing of customer receivable balances.
The Company’s expenditures for long-lived assets totaled $804.1 million during the nine months ended June 30, 2023 and $564.2 million during the nine months ended June 30, 2022. The table below presents these expenditures:
Total Expenditures for Long-Lived Assets
Nine Months Ended June 30,
2023
2022
Increase (Decrease)
(Millions)
Exploration and Production:
Capital Expenditures (1)
$
592.8
(2)
$
405.7
(3)
$
187.1
Pipeline and Storage:
Capital Expenditures
66.8
(2)
58.2
(3)
8.6
Gathering:
Capital Expenditures
55.4
(2)
28.6
(3)
26.8
Utility:
Capital Expenditures
88.7
(2)
71.0
(3)
17.7
All Other:
Capital Expenditures
0.4
0.7
(0.3)
$
804.1
$
564.2
$
239.9
(1)The nine months ended June 30, 2023 includes $124.8 million related to the acquisition of upstream assets acquired from SWN. The acquisition cost is reported as a component of Acquisition of Upstream Assets on the Consolidated Statement of Cash Flows.
(2)At June 30, 2023, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $52.8 million, $7.7 million, $2.8 million and $8.5 million, respectively, of non-cash capital expenditures. At September 30, 2022, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $83.0 million, $15.2 million, $10.7 million and $11.4 million, respectively, of non-cash capital expenditures.
(3)At June 30, 2022, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $62.0 million, $5.2 million, $2.5 million and $4.7 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.
Exploration and Production
The Exploration and Production segment capital expenditures for the nine months ended June 30, 2023 were primarily well drilling and completion expenditures in the Appalachian region, and also included $124.8 million of expenditures related to the acquisition of upstream assets from SWN on June 1, 2023, which is discussed further below. Exploration and Production segment capital expenditures for the nine months ended June 30, 2023 included $229.6 million spent in the Marcellus Shale area and $352.2 million spent in the Utica Shale area. These amounts included approximately $256.4 million spent to develop proved undeveloped reserves.
The Exploration and Production segment capital expenditures for the nine months ended June 30, 2022 were primarily well drilling and completion expenditures and included approximately $387.0 million for the Appalachian region (including $123.0 million in the Marcellus Shale area and $253.4 million in the Utica Shale area) and $18.7 million for the West Coast region. These amounts included approximately $130.8 million spent to develop proved undeveloped reserves.
Pipeline and Storage
The Pipeline and Storage segment capital expenditures for the nine months ended June 30, 2023 were primarily for additions, improvements and replacements to this segment's transmission and gas storage systems, which included system modernization expenditures that enhance the reliability and safety of the systems and reduce emissions. The Pipeline and Storage segment capital expenditures for the nine months ended June 30, 2022 were primarily for additions, improvements and replacements to this segment’s transmission and gas storage systems. In addition, the Pipeline and Storage segment capital expenditures for the nine months ended June 30, 2022 included expenditures related to Supply Corporation's FM100 Project ($23.0 million).
The majority of the Gathering segment capital expenditures for the nine months ended June 30, 2023 included expenditures related to the continued expansion of Midstream Company's Clermont, Covington, Trout Run and Wellsboro gathering systems, as discussed below. Midstream Company spent $14.7 million, $25.3 million, $6.8 million and $8.4 million, respectively, during the nine months ended June 30, 2023 on the development of the Clermont, Covington, Trout Run, and Wellsboro gathering systems. These expenditures were largely attributable to the installation of new in-field gathering pipelines, as well as the continued development of centralized station facilities, including increased compression horsepower, at the Clermont, Trout Run, and Wellsboro gathering systems. In the Tioga gathering system, which is part of Midstream Covington, expenditures were largely attributable to the expansion of on-pad and centralized pipeline and station facilities related to bringing new development online.
The majority of the Gathering segment capital expenditures for the nine months ended June 30, 2022 included expenditures related to the continued expansion of Midstream Company's Clermont and Covington gathering systems. Midstream Company spent $13.4 million and $12.9 million, respectively, during the nine months ended June 30, 2022 on the development of the Clermont and Covington gathering systems. These expenditures were largely attributable to the installation of new in-field gathering pipelines in the Clermont gathering system, as well as the development of new gathering facilities, including new in-field gathering pipelines and station upgrades in the Tioga gathering system.
Utility
The majority of the Utility segment capital expenditures for the nine months ended June 30, 2023 and June 30, 2022 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
In October 2021, the Company sold $30 million of fixed income mutual fund shares held in a grantor trust that was established for the benefit of Pennsylvania ratepayers. 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 $29 million in previously overcollected OPEB expenses in accordance with new rates that went into effect on October 1, 2021. In October 2022, the Company sold an additional $10 million of fixed income mutual fund shares held in the grantor trust. The proceeds from this sale were used to fund the second year installment of the 5-year pass back of overcollected OPEB expenses, as well as to diversify a portion of grantor trust investments into lower risk money market mutual fund shares. Please refer to the Rate Matters section that follows for additional discussion of this matter.
In March 2022, the Company completed the sale of certain oil and gas assets located in Tioga County, Pennsylvania effective as of October 1, 2021. The Company received net proceeds of $13.5 million from this sale. Under the full cost method of accounting for oil and natural gas properties, the sale proceeds were accounted for as a reduction of capitalized costs. Since the disposition did not significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center, the Company did not record any gain or loss from this sale.
On June 30, 2022, the Company completed the sale of Seneca’s California assets, all of which were in the Exploration and Production segment, to Sentinel Peak Resources California LLC for a total sale price of $253.5 million, consisting of $240.9 million in cash and contingent consideration valued at $12.6 million at closing. The fair value of the contingent consideration was $4.5 million at June 30, 2023. The Company pursued this sale given the strong commodity price environment and the Company’s strategic focus in the Appalachian Basin. Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed $10 million per year, with the amount of each annual payment calculated as $1.0 million for each $1 per barrel that the ICE Brent Average for each calendar year exceeds $95 per barrel up to $105 per barrel. The sale price, which reflected an effective date of April 1, 2022, was reduced for production revenues less expenses that were retained by Seneca from the effective date to the closing date. Under the full cost method of accounting for oil and natural gas properties, $220.7 million of the sale price at closing was accounted for as a reduction of capitalized costs since the disposition did not alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center. The remainder of the sale price ($32.8 million) was applied against assets that are not subject to the full cost method of accounting, with the Company recognizing a gain of $12.7 million on the sale of such assets. The majority of this gain related to the sale of emission allowances.
On June 1, 2023, the Company completed its acquisition of certain upstream assets located primarily in Tioga County, Pennsylvania from SWN Production Company, LLC ("SWN") for total consideration of $124.8 million. As part of the transaction, the Company acquired approximately 34,000 net acres in an area that is contiguous with existing Company-owned upstream assets. This transaction was accounted for as an asset acquisition and, as such, the purchase price was allocated to property, plant and equipment.
On April 13, 2023, the Company completed its acquisition of certain upstream assets located in Lycoming County in Northeast Pennsylvania from EXCO Production Company (PA), LLC and EXCO Resources (PA), LLC (collectively referred to as "EXCO") for total consideration of $11.5 million. As part of the transaction, the Company acquired approximately 1,145 net acres in that area of Pennsylvania. This transaction was accounted for as an asset acquisition and, as such, the purchase price was allocated to property, plant and equipment.
Project Funding
Over the past two years, the Company has been financing capital expenditures with cash from operations, short-term and long-term debt and proceeds from the sale of the Company's California assets. During the nine months ended June 30, 2023 and June 30, 2022, capital expenditures were funded with cash from operations and short-term debt. Going forward, the Company expects to use cash on hand, cash from operations and short-term or long-term borrowings, as needed, to finance capital expenditures. The level of short-term and/or long-term borrowings will depend upon the amount of cash provided by operations, which, in turn, will likely be most impacted by natural gas production and the associated commodity price realizations in the Exploration and Production segment. It will also likely depend on the timing of gas cost recovery in the Utility 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 natural gas properties, quicker development of existing natural 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. The amounts are also subject to modification for opportunities involving carbon emission reductions and/or energy transition including investments directly related to low- and no-carbon fuels. 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 business segments depends, to a large degree, upon market and regulatory conditions as well as legislative actions.
Financing Cash Flow
Consolidated short-term debt increased $78.5 million, to a total of $138.5 million, when comparing the balance sheet at June 30, 2023 to the balance sheet at September 30, 2022. The maximum amount of short-term debt outstanding during the nine months ended June 30, 2023 was $422.3 million. In addition to cash provided by operating activities, 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 items such as capital expenditures, asset purchases, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, 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. For example, during fiscal 2023, the Company repaid $549.0 million of long-term debt with maturity dates in March 2023. The Company utilized short-term borrowings and cash on hand to redeem the maturities, resulting in an increase in the short-term debt balance. As of June 30, 2023, the Company had outstanding commercial paper of $138.5 million. The Company did not have any short-term notes payable to banks as of June 30, 2023.
On February 28, 2022, the Company entered into a Credit Agreement (as amended from time to time, the "Credit Agreement") with a syndicate of twelve banks. The Credit Agreement replaced the previous Fourth Amended and Restated Credit Agreement and a previous 364-Day Credit Agreement. The Credit Agreement provides a $1.0 billion unsecured committed revolving credit facility with a maturity date of February 26, 2027.
On June 30, 2022, the Company entered into a 364-Day Credit Agreement with a syndicate of five banks, all of which are also lenders under the Credit Agreement. The 364-Day Credit Agreement provided an additional $250.0 million unsecured committed delayed draw term loan credit facility with a maturity date of June 29, 2023. The Company elected to draw $250.0 million under the facility on October 27, 2022. The Company used the proceeds for general corporate purposes, which included using $150.0 million for the November 2022 redemption of a portion of the Company's outstanding long-term debt with a
maturity date in March 2023. All indebtedness under the 364-Day Credit Agreement was repaid in May 2023 prior to its June 29, 2023 maturity date.
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 0.65 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 $400 million. Since July 1, 2018, the Company recorded non-cash, after-tax ceiling test impairments totaling $381.4 million. As a result, at June 30, 2023, $190.7 million was added back to the Company's total capitalization for purposes of the calculation under the Credit Agreement. On May 3, 2022, the Company entered into Amendment No. 1 to the Credit Agreement with the same twelve banks under the initial Credit Agreement. The amendment further modified the definition of consolidated capitalization, for purposes of calculating the debt to capitalization ratio under the Credit Agreement, to exclude, beginning with the quarter ended June 30, 2022, all unrealized gains or losses on commodity-related derivative financial instruments and up to $10 million in unrealized gains or losses on other derivative financial instruments included in Accumulated Other Comprehensive Income (Loss) within Total Comprehensive Shareholders' Equity on the Company's consolidated balance sheet. Under the Credit Agreement, such unrealized losses will not negatively affect the calculation of the debt to capitalization ratio, and such unrealized gains will not positively affect the calculation. At June 30, 2023, the Company’s debt to capitalization ratio, as calculated under the Credit Agreement was 0.45. The constraints specified in the Credit Agreement would have permitted an additional $3.27 billion in short-term and/or long-term debt to be outstanding at June 30, 2023 before the Company’s debt to capitalization ratio exceeded 0.65.
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 contains 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. 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.
On May 18, 2023, the Company issued $300.0 million of 5.50% notes due October 1, 2026.After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $297.5 million.The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade. Additionally, the interest rate payable on the notes will be subject to adjustment from time to time, with a maximum adjustment of 2.00%, such that the coupon will not exceed 7.50%, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to a rating below investment grade. A downgrade with a resulting increase to the coupon does not preclude the coupon from returning to its original rate if the Company's credit rating is subsequently upgraded. The proceeds of this debt issuance were used for general corporate purposes, including to repay all indebtedness under the $250.0 million unsecured committed delayed draw term loan under the 364-Day Credit Agreement.
None of the Company's long-term debt as of June 30, 2023 had a maturity date within the following twelve-month period. The Current Portion of Long-Term Debt at September 30, 2022 consisted of $500.0 million of 3.75% notes and $49.0 million of 7.395% notes, that each had maturity dates in March 2023. The Company utilized short-term borrowings and cash on hand to repay $150.0 million of these maturities in November 2022 and the remaining $399.0 million in March 2023.
The Company’s embedded cost of long-term debt was 4.70% at June 30, 2023 and 4.48% at June 30, 2022.
Under the Company’s existing indenture covenants at June 30, 2023, the Company would have been permitted to issue up to a maximum of approximately $3.53 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 the debt to capitalization ratio constraint under the Company's 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 $50.0 million (or 2.1%) of the Company’s long-term debt (as of June 30, 2023) 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.
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. The Company remains committed to the project and, on June 29, 2022, received an extension of time from FERC, until December 31, 2024, 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 June 30, 2023, approximately $55.8 million has been spent on the Northern Access project, including $24.2 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 June 30, 2023.
The Company did not make any contributions to its tax-qualified, noncontributory defined benefit retirement plan (Retirement Plan) or its VEBA trusts for its other post-retirement benefits during the nine months ended June 30, 2023, and does not anticipate making any such contributions during the remainder of fiscal 2023.
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 adopted several final regulations, other rules that may impact the Company have yet to be finalized. Rules adopted by the CFTC and other regulators could adversely impact the Company. While many of
those rules place specific conditions on the operations of swap dealers rather than directly on the Company, concern remains that swap dealers with whom the Company may transact will pass along their increased costs stemming from final rules through higher transaction costs and prices or other direct or indirect costs. Some of those rules also may apply directly to the Company and adversely impact its ability to trade swaps and over-the-counter derivatives, whether due to increased costs, limitations on trading capacity or for other reasons. Additionally, given the enforcement authority granted to the CFTC on anti-market manipulation, anti-fraud and anti-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 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 June 30, 2023, the Company determined that nonperformance risk associated with its natural gas price swap agreements, natural gas no cost collars and foreign currency contracts 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 2022 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.” As noted below, the Pennsylvania division currently has 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%, and directed the implementation of an earnings sharing mechanism to be in place beginning on April 1, 2018. The order also authorized the Company to recover approximately $15 million annually for pension and OPEB expenses from customers. Because the Company's future pension and OPEB costs were projected to be satisfied with existing funds held in reserve, in July 2022, Distribution Corporation made a filing with the NYPSC to effectuate a pension and OPEB surcredit to customers to offset these amounts being collected in base rates effective October 1, 2022. On September 16, 2022, the NYPSC issued an order approving the filing. The surcredit will remain in effect until modified by the NYPSC in another proceeding, or until December 31, 2024, whichever is earlier. With the implementation of this surcredit, Distribution Corporation will no longer be funding the Retirement Plan or its VEBA trusts in its New York jurisdiction.
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). On December 9, 2022, the Company filed a petition with the NYPSC to effectuate a system improvement tracker through which qualified pipeline replacement costs through September 30, 2024 would be tracked and recovered, and to recover certain deferred costs associated with the existing system modernization tracker, effective April 1, 2023. The NYPSC approved the petition by order dated March 17, 2023 contingent on the Company not filing a base rate case that would result in new rates becoming effective prior to October 1, 2024.
On January 19, 2023, the NYPSC issued an order in its Effects of COVID-19 on Utility Service (20-M-0266) and Energy Affordability for Low Income Utility Customers (14-M-0565) proceedings whereby a Phase 2 Utility Arrears Relief Program was authorized. Specifically, the order directed Distribution Corporation and certain other New York utilities to, among other things, address arrears on residential non-energy affordability program (EAP) ratepayer accounts that did not receive a credit under the NYPSC’s Phase 1 program and small commercial ratepayer accounts by issuing a one-time bill credit to such customers to reduce or eliminate accrued arrears through May 1, 2022. The credits shall be processed within 90 days of
the effective date of the order, provided that residential non-EAP customers who had their service disconnected for non-payment in 2022 shall be allowed the opportunity to have their service reinstated in order to receive the credit through June 30, 2023. The order further directs utilities to suspend residential service terminations for non-payment while arrears credits are applied to accounts through March 1, 2023, or 30 days after credits have been applied, whichever is later. The order authorizes the utilities to recover the Phase 2 costs (the arrears credits and associated carrying charges) through a surcharge. Utilities proposed various offsets to Phase 2 program costs, and Distribution Corporation has proposed certain offsets as part of an uncollectible expense reconciliation proposal. On February 17, 2023, Distribution Corporation made a filing with the NYPSC seeking approval of its uncollectible expense reconciliation mechanism. On July 19, 2023, the NYPSC noticed Distribution Corporation’s filing in the New York State Register indicating that public comment will be received on the filing until sixty days after publication or until September 18, 2023. Application of the proposed offsets and collection periods will be determined when the NYPSC rules on the uncollectible expense reconciliation filing.
Pennsylvania Jurisdiction
Distribution Corporation’s delivery rates effective through July 31, 2023 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. On October 28, 2022, Distribution Corporation made a filing with the PaPUC seeking an increase in its annual base rate operating revenues of $28.1 million with a proposed effective date of December 27, 2022. On December 8, 2022, the PaPUC issued an order suspending the filing until July 27, 2023 by operation of law unless directed otherwise by the PaPUC. Following discovery, the submission of testimony and an evidentiary hearing, the parties to the proceeding agreed to a settlement that authorizes, among other things, an increase in Distribution Corporation’s annual base rate operating revenues of $23 million as of August 1, 2023. On April 13, 2023, Distribution Corporation filed a joint petition with the PaPUC seeking approval of the settlement on behalf of all active parties to the proceeding. On June 15, 2023, the PaPUC issued an order granting the joint petition and adopting the settlement in full, without modification or correction.
Effective October 1, 2021, pursuant to a tariff supplement filed with the PaPUC, Distribution Corporation reduced base rates by $7.7 million in order to stop collecting OPEB expenses from customers. It also began to refund to customers overcollected OPEB expenses in the amount of $50.0 million. All matters with respect to this tariff supplement were finalized on February 24, 2022 with the PaPUC's approval of an Administrative Law Judge's Recommended Decision. Concurrent with that decision, the Company discontinued regulatory accounting for OPEB expenses and recorded an $18.5 million adjustment during the quarter ended March 31, 2022 to reduce its regulatory liability for previously deferred OPEB income amounts through September 30, 2021 and to increase Other Income (Deductions) on the consolidated financial statements by a like amount. The Company also increased customer refunds of overcollected OPEB expenses from $50.0 million to $54.0 million. All refunds specified in the tariff supplement are being 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 is no longer funding the grantor trust or its VEBA trusts in its Pennsylvania jurisdiction.
Pipeline and Storage
Supply Corporation filed a NGA Section 4 rate case at FERC on July 31, 2023 proposing rate increases to be effective February 1, 2024. The proposed rates reflect an annual cost of service of $385.4 million, a rate base of $1.32 billion and a proposed cost of equity of 15.12%. If the proposed rate increases finally approved at the end of the proceeding exceed the rates that were in effect at July 31, 2023, but are less than rates put into effect subject to refund on February 1, 2024, Supply Corporation would be required to refund the difference between the rates collected subject to refund and the final approved rates, with interest at the FERC-approved rate. If the rates approved at the end of the proceeding are lower than the rates in effect at July 31, 2023, such lower rates will become effective prospectively from the effective date provided by the applicable FERC order, and refunds with interest will be limited to the difference between the rates collected subject to refund and the rates in effect at July 31, 2023.
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 2021, the Company set methane intensity reduction targets at each of its businesses, an absolute greenhouse gas emissions reduction target for the consolidated Company, and
greenhouse gas reduction targets associated with the Company’s utility delivery system. In 2022, the Company began measuring progress against these reduction targets. 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. 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. For example, the Inflation Reduction Act of 2022 (IRA) legislation was signed into law on August 16, 2022. The IRA includes a methane charge that is expected to be applicable to the reported annual methane emissions of certain oil and gas facilities, above specified methane intensity thresholds, starting in calendar year 2024. This portion of the IRA is to be administered by the EPA and potential fees will begin with emissions reported for calendar year 2024. The EPA regulates greenhouse gas emissions pursuant to the Clean Air Act. The regulations implemented by the EPA impose more stringent leak detection and repair requirements, and further address reporting and control of methane and volatile organic compound emissions. The Company must continue to comply with all applicable regulations. Additionally, a number of states have adopted energy strategies or plans with aggressive goals for the reduction of greenhouse gas emissions. Pennsylvania has a methane reduction framework with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines. Pennsylvania's Governor also entered the Commonwealth into a cap-and-trade program known as the Regional Greenhouse Gas Initiative, however, the Commonwealth's participation is currently stayed due to ongoing litigation. Federal, state or local governments may provide tax advantages and other subsidies to support alternative energy sources, mandate the use of specific fuels or technologies, or promote research into new technologies to reduce the cost and increase the scalability of alternative energy sources. The NYPSC, for example, initiated a proceeding to consider climate-related financial disclosures at the utility operating company level, and the 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. In May 2023, New York State passed legislation that prohibits the installation of fossil fuel burning equipment and building systems in new buildings commencing on or after December 31, 2025, subject to certain exemptions. 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 statewide 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 and has commenced pre-proposal outreach initiatives to investigate development of a cap-and-invest program in New York. 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.
Effects of Inflation
The Company’s operations are sensitive to increases in the rate of inflation because of its operational and capital spending requirements in both its regulated and non-regulated businesses. For the regulated businesses, recovery of increasing costs from customers can be delayed by the regulatory process of a rate case filing. For the non-regulated businesses, prices received for services performed or products produced are determined by market factors that are not necessarily correlated to the underlying costs required to provide the service or product.
Safe Harbor for Forward-Looking Statements
The Company is including the following cautionary statement in this Quarterly Report on 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.Changes in economic conditions, including inflationary pressures, supply chain issues, liquidity challenges, 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;
6.Changes in the price of natural gas;
7.The creditworthiness or performance of the Company’s key suppliers, customers and counterparties;
8.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;
9.Impairments under the SEC’s full cost ceiling test for natural gas reserves;
10.Increased costs or delays or changes in plans with respect to Company projects or related projects of other companies, as well as difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators;
11.The Company's ability to complete planned strategic transactions;
12.Changes in price differentials between similar quantities of natural gas sold at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations;
13.The impact of information technology disruptions, cybersecurity or data security breaches;
14.Factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas reserves, including among others geology, lease availability and costs, title disputes, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations;
15.Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits;
16.Other changes in price differentials between similar quantities of natural gas having different quality, heating value, hydrocarbon mix or delivery date;
17.The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company;
18.Negotiations with the collective bargaining units representing the Company's workforce, including potential work stoppages during negotiations;
19.Uncertainty of natural gas reserve estimates;
20.Significant differences between the Company’s projected and actual production levels for natural gas;
21.Changes in demographic patterns and weather conditions (including those related to climate change);
22.Changes in the availability, price or accounting treatment of derivative financial instruments;
23.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;
24.Economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities or acts of war, as well as economic and operational disruptions due to third-party outages;
25.Significant differences between the Company’s projected and actual capital expenditures and operating expenses; or
26.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.
Forward-looking and other statements in this Quarterly Report on Form 10-Q regarding methane and greenhouse gas reduction plans and goals are not an indication that these statements are necessarily material to investors or required to be disclosed in our filings with the SEC. In addition, historical, current and forward-looking statements regarding methane and greenhouse gas emissions may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve and assumptions that are subject to change in the future.
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 June 30, 2023.
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 June 30, 2023 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
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 2022 Form 10-K, as updated by Item 1A of Part II of the Company's Quarterly Report on Form 10-Q for the quarter ended December 31, 2022, have not materially changed other than as set forth below. The risk factor presented below supersedes the risk factor having the same caption in the 2022 Form 10-K and the December 31, 2022 Form 10-Q and should otherwise be read in conjunction with all of the risk factors disclosed in the 2022 Form 10-K.
STRATEGIC RISKS
Climate change, and the regulatory, legislative, consumer behaviors and capital access developments related to climate change, may adversely affect operations and financial results.
Climate change, and the laws, regulations and other initiatives to address climate change, may impact the Company’s financial results. In early 2021, the U.S. rejoined the Paris Agreement, the international effort to establish emissions reduction goals for signatory countries. Under the Paris Agreement, signatory countries are expected to submit their nationally determined contributions to curb greenhouse gas emissions and meet the agreed temperature objectives every five years. On April 22, 2021, the federal administration announced the U.S. nationally determined contribution to achieve a fifty to fifty-two percent reduction from 2005 levels in economy-wide net greenhouse gas pollution by 2030. In addition to the federal reentry into the Paris Agreement, state and local governments, non-governmental organizations, investment firms, and financial institutions have made, and will likely continue to make, more aggressive efforts to reduce emissions and advance the objectives of the Paris Agreement. Executive orders from the federal administration, in addition to federal, state and local legislative and regulatory initiatives proposed or adopted in an attempt to limit the effects of climate change, including greenhouse gas emissions, could have significant impacts on the energy industry including government-imposed limitations, prohibitions or moratoriums on the use and/or production of gas, establishment of a carbon tax and/or methane fee, lack of support for system modernization, as well as accelerated depreciation of assets and/or stranded assets.
Federal and state legislatures have from time to time considered bills that would establish a cap-and-trade program, cap-and-invest program, methane fee or carbon tax to incent the reduction of greenhouse gas emissions. For example, in August 2022, the federal Inflation Reduction Act was signed into law, which includes a methane charge that is expected to be applicable to the reported annual methane emissions of certain oil and gas facilities, above specified methane intensity thresholds, starting in calendar year 2024. In addition, the New York State legislature, in early 2021, proposed a bill known as the Climate and Community Investment Act, which proposed an escalating fee starting at $55 per short ton of carbon dioxide equivalent on any carbon-based fuels sold, used or brought into the state. That bill did not pass, but similar legislation may be proposed in the future. In December 2022, New York’s Climate Action Council issued a final scoping plan recommending the implementation of a cap-and-invest program in New York. In January 2023, New York’s Governor announced a cap-and-invest program as part of her 2023 State of the State address. The Governor directed the Department of Environmental Conservation and the New York State Energy Research and Development Authority to advance an economywide cap-and-invest program that establishes a declining cap on greenhouse gas emissions, and invests in programs to drive emissions reductions. If this proposed program becomes effective and the Company becomes subject to new or revised cap-and-trade programs, cap-and-invest programs, methane charges, fees for carbon-based fuels or other similar costs or charges, the Company may experience additional costs and incremental operating expenses, which would impact our future earnings and cash flows.
A number of states have also adopted energy strategies or plans with goals that include the reduction of greenhouse gas emissions. For example, Pennsylvania has a methane reduction framework for the natural gas industry which has resulted in permitting changes with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines. In addition, the NYPSC initiated a proceeding to consider climate-related financial disclosures at the utility operating level, and in 2019, the New York State legislature passed the CLCPA, which created emission reduction and electric generation mandates, and could ultimately impact the Utility segment’s customer base and business. Pursuant to the CLCPA, New York's Climate
Action Council approved a final scoping plan that includes recommendations to strategically downsize and decarbonize the natural gas system and curtail use of natural gas and natural gas appliances. The final scoping plan was approved and adopted on December 19, 2022 and includes detailed recommendations to meet the CLCPA’s emissions reduction targets in the transportation, buildings, electricity, industry, agriculture & forestry and waste sectors. The final scoping plan also recommends statewide and cross-sector policies relevant to gas system transition, economywide strategies, land use, local government and adaptation and resilience.
Legislation or regulation that aims to reduce greenhouse gas emissions could also include natural gas bans, greenhouse gas emissions limits and reporting requirements, carbon taxes and/or similar fees on carbon dioxide, methane or equivalent emissions, restrictive permitting, increased efficiency standards requiring system remediation and/or changes in operating practices, and incentives or mandates to conserve energy or use renewable energy sources. NYDEC finalized its Part 203 Oil and Gas Sector Rule in March 2022, which significantly increases leak detection and repair inspections, recordkeeping, reporting, and notification requirements for multiple sources along city gates, transmission pipelines, compressor stations, storage facilities, and gathering lines. In May 2023, New York State passed legislation that prohibits the installation of fossil fuel burning equipment and building systems in new buildings commencing on or after December 31, 2025, subject to certain exemptions.
Additionally, the trend toward increased energy conservation, change in consumer behaviors, competition from renewable energy sources, and technological advances to address climate change may reduce the demand for natural gas. For further discussion of the risks associated with environmental regulation to address climate change, refer to Item 2, MD&A under the heading “Environmental Matters.”
Further, recent trends directed toward a low-carbon economy could shift funding away from, or limit or restrict certain sources of funding for, companies focused on fossil fuel-related development or carbon-intensive investments. To the extent financial markets view climate change and greenhouse gas emissions as a financial risk, the Company’s cost of and access to capital could be negatively impacted.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
On April 3, 2023, the Company issued a total of 7,580 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 758 shares per director. All of these unregistered shares were issued under the Company’s 2009 Non-Employee Director Equity Compensation Plan as partial consideration for such directors’ services during the quarter ended June 30, 2023. The Company issued an additional 425 unregistered shares in the aggregate on April 14, 2023 pursuant to the dividend reinvestment feature of the DCP, to the six non-employee directors who participate in the DCP. 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)
Apr. 1 - 30, 2023
12,367
$56.57
—
6,971,019
May 1 - 31, 2023
12,402
$53.96
—
6,971,019
June 1 - 30, 2023
13,220
$51.68
—
6,971,019
Total
37,989
$54.02
—
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, if any, tendered to the Company by holders of stock-based compensation awards for the payment of applicable withholding taxes. During the quarter ended June 30, 2023, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase program. Of the 37,989 shares purchased other than through a publicly announced share repurchase program, 37,954 were purchased for the Company's 401(k) plans and 35 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.
During the quarter ended June 30, 2023, no director or officer (as defined in Rule 16a-1(f) promulgated under the Exchange Act) of the Company adopted or terminated any “Rule 10b5–1 trading arrangement” or any “non-Rule 10b5–1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K.
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 nine months ended June 30, 2023 and 2022, (ii) the Consolidated Statements of Comprehensive Income for the nine months ended June 30, 2023 and 2022, (iii) the Consolidated Balance Sheets at June 30, 2023 and September 30, 2022, (iv) the Consolidated Statements of Cash Flows for the nine months ended June 30, 2023 and 2022 and (v) the Notes to Condensed Consolidated Financial Statements.
104
Cover Page Interactive Data File (embedded within the Inline XBRL document)
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Incorporated herein by reference as indicated.
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In accordance with Item 601(b)(32)(ii) of Regulation S-K and SEC Release Nos. 33-8238 and 34-47986, Final Rule: Management’s Reports on Internal Control Over Financial Reporting and Certification of Disclosure in Exchange Act Periodic Reports, the material contained in Exhibit 32 is “furnished” and not deemed “filed” with the SEC and is not to be incorporated by reference into any filing of the Registrant under the Securities Act of 1933 or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language contained in such filing, except to the extent that the Registrant specifically incorporates it by reference.
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
