Item 2. Management’s Discussion and Analysis
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. 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
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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. In addition to expansion projects, the Company continues to focus on the ongoing modernization of its regulated Pipeline and Storage and Utility assets. The Company reports financial results for four business segments. For a discussion of the Company's earnings, refer to the Results of Operations section below.
The Company has continued to pursue development projects to expand its Pipeline and Storage segment. One project on Supply Corporation’s system, referred to as the Tioga Pathway Project, is an expansion and modernization project that would allow for the transportation of 190,000 Dth per day of shale gas supplies from a new interconnection in northwest Tioga County, Pennsylvania to an existing Supply Corporation interconnection with Tennessee Gas Pipeline Company, LLC at Ellisburg and a new virtual delivery point into an existing Transcontinental Gas Pipe Line Company, LLC (“Transco”) capacity lease, providing access to Mid-Atlantic markets. Supply Corporation filed a Section 7 (c) application with FERC for the project on August 21, 2024. The Tioga Pathway Project has a target in-service date in late calendar 2026 and a preliminary cost estimate of approximately $101 million. The Tioga Pathway Project is discussed in more detail in the Capital Resources and Liquidity section that follows.
From a rate perspective, Distribution Corporation, in its New York jurisdiction, reached a settlement with the parties to its rate case proceeding. On December 19, 2024, the NYPSC issued an order approving the settlement. The settlement, effective January 1, 2025, establishes a three-year rate plan that reflects a return on equity of 9.7% and authorizes a revenue requirement increase of $57.3 million in fiscal 2025, an additional revenue requirement increase of $15.8 million in fiscal 2026, and an additional revenue requirement increase of $12.7 million in fiscal 2027. The settlement also includes standard make-whole language allowing full recovery of revenues that would have been billed at the new rates between October 1, 2024 and December 31, 2024. In addition, Supply Corporation filed an NGA Section 4 rate case at FERC on July 31, 2023. Settlement rates became effective on February 1, 2024 under a settlement that was approved by FERC without modification on June 11, 2024, and which is estimated to increase Supply Corporation’s revenues by approximately $56 million on an annual basis. For further discussion of Distribution Corporation and Supply Corporation rate matters, refer to the Rate Matters section below.
As discussed in the following Critical Accounting Estimates section, the Company uses the full cost method of accounting for determining the book value of its exploration and production properties and that book value is subject to a quarterly ceiling test. In addition to the non-cash impairment charges under the ceiling test that the Company recorded during fiscal 2024, the Company recorded a non-cash impairment charge under the ceiling test for the quarter ended December 31, 2024 of $108.3 million ($79.1 million after-tax). Please refer to the Critical Accounting Estimates section below for a sensitivity analysis concerning commodity price changes.
From a financing perspective, given the impairments recorded since June 30, 2024, under its existing indenture covenants, the Company is precluded from issuing incremental long-term debt from January 1, 2025 to June 13, 2025, the maturity date of the Company's remaining indebtedness outstanding under its 1974 indenture. To the extent the Company wishes to relieve its obligations to comply with the 1974 indenture's restrictions, the Company expects to be able to place future principal and interest payments in trust for the benefit of bondholders pursuant to the terms of the 1974 indenture. Depositing such future principal and interest payments in trust would effectively relieve the Company from its obligations to comply with the 1974 indenture’s restrictions, including those on the issuance of incremental long-term debt.
In February 2024, eleven lenders in the syndicate of twelve banks under the Credit Agreement consented to a one-year extension of the maturity date of the Credit Agreement from February 26, 2027 to February 25, 2028. In May 2024, three of the lenders in the syndicate assumed the commitments of the sole non-extending lender. In January 2025, the Company and the eleven banks in the syndicate consented to a second one-year extension on the maturity date from February 25, 2028 to February 23, 2029, such that the Company has aggregate commitments available under the Credit Agreement in the full amount of $1.0 billion through February 23, 2029.
The Company began repurchasing outstanding shares of its common stock during the quarter ended March 31, 2024 under a share repurchase program authorized by the Company’s Board of Directors. The program authorizes the Company to repurchase up to an aggregate amount of $200 million of its outstanding common stock in the open market or through privately negotiated transactions. During the quarter ended December 31, 2024, the Company executed transactions to repurchase 548,596 shares at an average price of $61.27 per share. With broker fees and excise taxes, the total cost of these repurchases amounted to $33.9 million. As of December 31, 2024, the Company has repurchased 1,694,855 shares under the share repurchase program at an average price of $57.93, for a total cost of $99.1 million (including broker fees and excise taxes). These matters are discussed further in the Capital Resources and Liquidity section that follows.
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The Company expects to use cash on hand, cash from operations, and short-term and long-term borrowings, as needed, to meet its financing needs for the remainder of fiscal 2025, including the redemption of two of the Company’s long-term debt maturities totaling $500.0 million that are scheduled to mature in 2025. The Company continues to evaluate these financing needs and options to meet them. Given the current economic conditions, which include continued inflationary pressures, volatile interest rates and a change in administration at the federal level, the cost and/or availability of capital may be impacted, but the Company continues to expect to meet its financing needs.
CRITICAL ACCOUNTING ESTIMATES
For a complete discussion of critical accounting estimates, refer to "Critical Accounting Estimates" in Item 7 of the Company's 2024 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.
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 exploration and production properties, with natural gas properties in the Appalachian Region being the primary component after the fiscal 2022 sale of the Company's California exploration and production properties. 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 exploration and production reserves based on an unweighted arithmetic average of first day of the month commodity 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 exploration and production 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 exploration and production properties exceeds the ceiling, a non-cash impairment charge must be recorded to reduce the book value of such properties to the calculated ceiling. The book value of the exploration and production properties exceeded the ceiling at December 31, 2024, resulting in a non-cash impairment charge of $108.3 million ($79.1 million after-tax) for the quarter ended December 31, 2024. The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended December 31, 2024, based on the quoted Henry Hub spot price for natural gas, was $2.13 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 December 31, 2024. Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.) The following table illustrates the sensitivity of the ceiling test calculation to commodity price changes, specifically showing the additional impairment that the Company would have recorded at December 31, 2024 if natural gas prices were $0.25 per MMBtu lower than the average prices used at December 31, 2024 (all amounts are presented after-tax). These calculated amounts are based solely on price changes and do not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates.
Ceiling Testing Sensitivity to Commodity Price Changes
(Millions) $0.25/MMBtu
Decrease in
Natural Gas Prices
Calculated Impairment under Sensitivity Analysis
$ 473.7
Actual Impairment Recorded at December 31, 2024 79.1
Additional Impairment
$ 394.6
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 "Exploration and Development Costs" under "Critical Accounting Estimates" in Item 7 of the Company's 2024 Form 10-K.
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RESULTS OF OPERATIONS
Earnings
The Company's earnings were $45.0 million for the quarter ended December 31, 2024 compared to earnings of $133.0 million for the quarter ended December 31, 2023. The decrease in earnings of $88.0 million is primarily the result of a loss recognized in the Exploration and Production segment. Lower earnings in the Gathering Segment and losses in the Corporate and All Other categories also contributed to the decrease. Higher earnings in the Pipeline and Storage segment and Utility segment partially offset these decreases.
The Company's earnings for the quarter ended December 31, 2024 included non-cash impairment charges of $141.8 million ($103.6 million after-tax) in the Exploration and Production segment, consisting mostly of ceiling test impairment charges of $108.3 million ($79.1 million after-tax), as discussed above. The remaining charges are related to the impairment of certain water disposal assets. Note that all amounts used in earnings discussions are after-tax amounts, unless otherwise noted.
Earnings (Loss) by Segment
Three Months Ended
December 31,
(Thousands) 2024 2023 Increase
(Decrease)
Exploration and Production $ (46,777) $ 52,483 $ (99,260)
Pipeline and Storage 32,454 24,055 8,399
Gathering 27,145 28,825 (1,680)
Utility 32,499 26,551 5,948
Total Reportable Segments 45,321 131,914 (86,593)
All Other (193) (121) (72)
Corporate (142) 1,227 (1,369)
Total Consolidated $ 44,986 $ 133,020 $ (88,034)
Exploration and Production
Exploration and Production Operating Revenues
Three Months Ended
December 31,
(Thousands) 2024 2023 Increase
(Decrease)
Gas Produced in Appalachia (after Hedging) $ 247,187 $ 252,416 $ (5,229)
Other 1,673 1,603 70
$ 248,860 $ 254,019 $ (5,159)
Production Volumes
Three Months Ended
December 31,
2024 2023 Increase
(Decrease)
Gas Production per MMcf 97,717 100,757 (3,040)
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Average Prices
Three Months Ended
December 31,
2024 2023 Increase
(Decrease)
Average Gas Price/Mcf
Weighted Average $ 2.23 $ 2.31 $ (0.08)
Weighted Average After Hedging $ 2.53 $ 2.51 $ 0.02
2024 Compared with 2023
Operating revenues for the Exploration and Production segment decreased $5.2 million for the quarter ended December 31, 2024 as compared with the quarter ended December 31, 2023. Gas production revenue after hedging decreased $5.2 million due to the impact of a 3.0 Bcf decrease in natural gas production partially offset by a $0.02 per Mcf increase in the weighted average price of natural gas after hedging. The decrease in natural gas production was largely due to lower production in the Marcellus and Utica wells in the Appalachian region.
The Exploration and Production segment's loss for the quarter ended December 31, 2024 was $46.8 million, a decrease of $99.3 million when compared with earnings of $52.5 million for the quarter ended December 31, 2023. This decrease can be primarily attributed to non-cash impairments of assets ($103.6 million), including ceiling test impairments of $79.1 million and a $24.5 million impairment of certain water disposal assets recorded during the quarter ended December 31, 2024, as well as lower natural gas production ($6.0 million). In conjunction with the ceiling test impairment, there was a $1.0 million earnings reduction associated with the remeasurement of state deferred income taxes. A decline in other income ($1.7 million) also contributed to the decrease in earnings. These decreases were partially offset by higher natural gas prices after hedging ($1.9 million), lower depletion expense ($6.8 million) and lower lease operating and transportation expenses ($1.1 million). There was also an unrealized loss recognized in the three-month period ended December 31, 2024 ($0.3 million) on contingent consideration received as part of the 2022 California asset sale, compared to an unrealized loss that was recognized in the three-month period ended December 31, 2023 ($3.0 million) on such contingent consideration. The decline in other income was mainly attributed to business interruption insurance proceeds received during the quarter ended December 31, 2023 related to a pipeline outage impacting Seneca’s ability to market gas. The decrease in depletion expense was primarily due to the net decrease in production combined with a $0.06 per Mcf decrease in the depletion rate largely due to ceiling test impairments recorded in the third and fourth quarters of fiscal 2024 that lowered Seneca’s full cost pool depletable base. The decrease in lease operating and transportation expenses was primarily the result of lower gathering and transportation costs combined with lower workover and salt water disposal expenses.
Pipeline and Storage
Pipeline and Storage Operating Revenues
Three Months Ended
December 31,
(Thousands) 2024 2023 Increase
(Decrease)
Firm Transportation $ 81,086 $ 71,495 $ 9,591
Interruptible Transportation 118 123 (5)
81,204 71,618 9,586
Firm Storage Service 24,993 21,291 3,702
Interruptible Storage Service — 1 (1)
Other 415 1,503 (1,088)
$ 106,612 $ 94,413 $ 12,199
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Pipeline and Storage Throughput
Three Months Ended
December 31,
(MMcf) 2024 2023 Increase
(Decrease)
Firm Transportation 202,882 200,101 2,781
Interruptible Transportation 62 118 (56)
202,944 200,219 2,725
2024 Compared with 2023
Operating revenues for the Pipeline and Storage segment increased $12.2 million for the quarter ended December 31, 2024 as compared with the quarter ended December 31, 2023. The increase in operating revenues was primarily due to an increase in transportation revenues of $9.6 million and an increase in storage revenues of $3.7 million, partially offset by a decrease in other revenues of $1.1 million. The increase in transportation and storage revenues was primarily attributable to an increase in Supply Corporation's transportation and storage rates effective February 1, 2024, in accordance with Supply Corporation's rate case settlement. The settlement was approved by FERC on June 11, 2024. The decrease in other revenues primarily reflects lower cashout revenues, which are completely offset by purchased gas expense, and an adjustment to match electric surcharge revenues to electric power costs recorded in operation and maintenance expense.
Transportation volume for the quarter ended December 31, 2024 increased by 2.7 Bcf from the prior year's quarter ended December 31, 2023. The increase in transportation volume for the quarter ended December 31, 2024 is primarily due to an increase in volume from new long-term contracts combined with an increase in volume from colder weather. These were partially offset by lower capacity utilization with certain contract shippers and certain contract expirations and revisions. Volume fluctuations, other than those caused by the addition or termination of contracts, generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.
The Pipeline and Storage segment’s earnings for the quarter ended December 31, 2024 were $32.5 million, an increase of $8.4 million when compared with earnings of $24.1 million for the quarter ended December 31, 2023. The increase in earnings was primarily due to the earnings impact of higher operating revenues ($9.6 million), as discussed above. This increase was partially offset by increases in operating expenses ($0.9 million) and higher income tax expense ($0.5 million). The increase in operating expenses was primarily due to higher pipeline integrity costs combined with an increase in personnel costs. The increase in income tax expense is mainly due to higher state income tax expense due to higher pre-tax earnings.
Gathering
Gathering Operating Revenues
Three Months Ended
December 31,
(Thousands) 2024 2023 Increase
(Decrease)
Gathering Revenues $ 61,131 $ 62,588 $ (1,457)
Gathering Volume
Three Months Ended
December 31,
2024 2023 Increase
(Decrease)
Gathered Volume - (MMcf) 120,961 124,261 (3,300)
2024 Compared with 2023
Operating revenues for the Ga thering segme nt decreased $1.5 million f or the quarter ended December 31, 2024 as compared with the quarter ended December 31, 2023, which was driven primarily by a 3.3 Bcf decrease in gathered volume.
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Gathered volume decreased 1.9 Bcf and 1.4 Bcf in the Gathering segment's eastern development areas (Trout Run and Tioga) and western development area (Clermont), respectively. The net decrease in gathered volume can be attributed to a decrease 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 December 31, 2024 were $27.1 million, a decrease of $1.7 million when compared with earnings of $28.8 million for the quarter ended December 31, 2023. The decrease in earnings was primarily due to lower gathering revenues ($1.2 million) and higher depreciation expense ($0.8 million). The decrease in gathering revenues was driven by the decrease in gathered volume, as discussed above. The increase in depreciation expense was largely due to additional plant in-service associated with the Tioga gathering system. These decreases in earnings were partially offset by a decrease in income tax expense ($0.4 million) due to lower state income taxes driven by lower pre-tax income and a reduction in the Pennsylvania state income tax rate.
Utility
Utility Operating Revenues
Three Months Ended
December 31,
(Thousands) 2024 2023 Increase
(Decrease)
Retail Sales Revenues:
Residential $ 171,365 $ 149,656 $ 21,709
Commercial 23,212 21,209 2,003
Industrial 1,384 911 473
195,961 171,776 24,185
Transportation 30,622 30,798 (176)
Other 1,926 (567) 2,493
$ 228,509 $ 202,007 $ 26,502
Utility Throughput
Three Months Ended
December 31,
(MMcf) 2024 2023 Increase
(Decrease)
Retail Sales:
Residential 18,476 17,982 494
Commercial 2,919 2,800 119
Industrial 199 138 61
21,594 20,920 674
Transportation 16,942 17,528 (586)
38,536 38,448 88
Degree Days
Three Months Ended December 31, Percent Colder (Warmer) Than
Normal 2024 2023 Normal (1)
Prior Year (1)
Buffalo, NY 2,253 1,884 1,858 (16.4) % 1.4 %
Erie, PA 1,894 1,697 1,664 (10.4) % 2.0 %
(1) Percents compare actual 2024 degree days to normal degree days and actual 2024 degree days to actual 2023 degree days.
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2024 Compared with 2023
Operating revenues for the Utility segment increased $26.5 million for the quarter ended December 31, 2024 as compared with the quarter ended December 31, 2023. This increase resulted from a $24.2 million increase in retail gas sales revenue and a $2.5 million increase in other revenue, which were partially offset by a $0.2 million decrease in transportation revenue. The increase in retail gas sales revenue is primarily the result of the impact of new base delivery rates in Distribution Corporation's New York jurisdiction pursuant to a settlement approved by the NYPSC on December 19, 2024. Additional details regarding the base rate regulatory proceeding can be found in Note 10 - Regulatory Matters. This increase also reflects higher purchased gas revenues resulting from a 0.7 Bcf increase in throughput due to cooler temperatures combined with an increase in the cost of gas sold (per Mcf). 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 increase in other revenue was mainly due to the elimination of the refund provision that was required to defer and return the income tax benefits resulting from the 2017 Tax Reform Act to customers ($3.3 million). The refund provision is no longer necessary because Distribution Corporation's new base delivery rates now reflect a revenue requirement determined with the current federal income tax rate of 21% and the refund of excess accumulated deferred income taxes.
The Utility segment’s earnings for the quarter ended December 31, 2024 were $32.5 million, an increase of $5.9 million when compared with earnings of $26.6 million for the quarter ended December 31, 2023. The increase was primarily due to the impact of new base rates in the Utility segment's New York jurisdiction ($7.9 million) and an increase in other income ($3.2 million), which was mainly attributable to the recognition of non-service pension and post-retirement benefit income in accordance with the rate settlement. These factors were partially offset by higher interest expense ($1.8 million), higher operating expenses ($1.2 million), higher depreciation expense ($0.6 million), an increase in income tax expense ($0.6 million), and a decrease in margin due to lower usage and weather ($0.3 million). The increase in interest expense was primarily due to an increase in outstanding intercompany debt balances. The increase in operating expenses was mainly attributable to higher personnel costs.
The impact of weather variations on cash flows and customer bills in the Utility segment is mitigated by a WNA. The WNA, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the Utility segment. In addition, in periods of colder than normal weather, the WNA benefits the Utility segment's customers. For the quarter ended December 31, 2024, the WNA preserved earnings of approximately $2.0 million and $1.2 million, respectively, in the Utility segment’s New York and Pennsylvania rate jurisdictions, as the weather was warmer than normal in both jurisdictions. For the quarter ended December 31, 2023, the WNA preserved earnings of approximately $1.4 million in the Utility segment’s New York jurisdiction and $0.5 million in the Utility segment's Pennsylvania jurisdiction, as the weather was warmer than normal.
Corporate and All Other
2024 Compared with 2023
Corporate and All Other operations recorded a net loss of $0.3 million for the quarter ended December 31, 2024, a decrease of $1.4 million when compared with earnings of $1.1 million for the quarter ended December 31, 2023. The decrease was primarily attributable to changes in unrealized gains and losses on investments in equity securities. During the quarter ended December 31, 2024, the Company recorded unrealized losses of $2.1 million. During the quarter ended December 31, 2023, the Company recorded unrealized gains of $0.8 million. These changes were partially offset by realized gains from investment securities sold in the current quarter ($1.2 million). There were no realized gains or losses during the quarter ended December 31, 2023.
Other Income (Deductions)
Net other income on the Consolidated Statements of Income was $7.7 million for the quarter ended December 31, 2024, compared to net other income of $3.7 million for the quarter ended December 31, 2023, for an increase of $4.0 million. This increase can be attributed primarily to a $5.2 million increase in non-service pension and post-retirement benefit income along with a $3.8 million benefit from the quarter-over-quarter revaluation of the contingent consideration received from the 2022 California asset sale. These increases were offset by quarter-over-quarter changes in the value of investment securities. During the quarter ended December 31, 2024, there were net losses of $1.2 million on investment securities. However, during the quarter ended December 31, 2023, there were net gains of $1.3 million on investment securities. Another offsetting factor
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was the non-recurrence of $2.0 million of business interruption insurance proceeds received during the quarter ended December 31, 2023 related to a pipeline outage that impacted Seneca's ability to market its gas.
Interest Expense on Long-Term Debt
Interest expense on long-term debt on the Consolidated Statement of Income increased $4.9 million for the quarter ended December 31, 2024 as compared to the quarter ended December 31, 2023. In April 2024, the Company elected to draw a total of $300.0 million under a delayed draw term loan credit facility, which was the primary driver of the increase. These borrowings had a locked-in weighted average interest rate of 6.30% for the quarter ended December 31, 2024.
CAPITAL RESOURCES AND LIQUIDITY
The Company’s primary source of cash during the three-month periods ended December 31, 2024 and December 31, 2023 consisted of cash provided by operating activities and net proceeds from short-term borrowings.
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 2025, the Company expects to use cash provided by operating activities, as well as net proceeds from short-term and long-term borrowings, to fund the Company's capital expenditures. Looking forward to 2026, based on current commodity prices, cash provided by operating activities is again expected to exceed capital expenditures. The Company also has two long-term debt maturities in 2025, totaling $500.0 million, which the Company anticipates funding with long-term borrowings. These cash flow projections do not reflect the impact of acquisitions or divestitures that may arise in the future.
Operating Cash Flow
Internally generated cash from operating activities consists of net income available for common stock, adjusted for non-cash expenses, non-cash income, gains and losses associated with investing and financing activities, and changes in operating assets and liabilities. Non-cash items include depreciation, depletion and amortization, impairment of assets, 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, weather and regulatory lag may also significantly impact cash flow. The impact of weather on cash flow is tempered in the Pipeline and Storage segment by the straight fixed-variable rate design used by Supply Corporation and Empire. The weather impact on cash flow in the Utility segment is mitigated by a WNA in both its New York and Pennsylvania rate jurisdictions.
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. The pricing protection obtained from derivative financial instruments will fluctuate over time as instruments expire and are replaced with new instruments reflecting current commodity prices of natural gas.
Net cash provided by operating activities totaled $220.1 million for the three months ended December 31, 2024, a decrease of $50.8 million compared with $270.9 million provided by operating activities for the three months ended December 31, 2023. The decrease in cash provided by operating activities primarily reflects lower cash provided by operating activities in the Exploration and Production segment due to lower cash receipts from natural gas production in the Appalachian region.
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Investing Cash Flow
Expenditures for Long-Lived Assets
The Company’s expenditures for long-lived assets totaled $192.1 million during the three months ended December 31, 2024 and $235.7 million during the three months ended December 31, 2023. The table below presents these expenditures:
Total Expenditures for Long-Lived Assets
Three Months Ended December 31, 2024 2023 Increase (Decrease)
(Millions)
Exploration and Production:
Capital Expenditures $ 122.6 (1) $ 161.0 (2) $ (38.4)
Pipeline and Storage:
Capital Expenditures 19.8 (1) 24.6 (2) (4.8)
Gathering:
Capital Expenditures 13.0 (1) 19.6 (2) (6.6)
Utility:
Capital Expenditures 36.5 (1) 30.5 (2) 6.0
All Other:
Capital Expenditures 0.2 — 0.2
$ 192.1 $ 235.7 $ (43.6)
(1) At December 31, 2024, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $56.3 million, $4.4 million, $6.0 million and $4.9 million, respectively, of non-cash capital expenditures. At September 30, 2024, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $63.3 million, $14.4 million, $21.7 million and $20.6 million, respectively, of non-cash capital expenditures.
(2) At December 31, 2023, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $74.9 million, $5.5 million, $11.1 million and $6.4 million, respectively, of non-cash capital expenditures. At September 30, 2023, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $43.2 million, $31.8 million, $20.6 million and $13.6 million, respectively, of non-cash capital expenditures.
Exploration and Production
The Exploration and Production segment capital expenditures for the three months ended December 31, 2024 were primarily well drilling and completion expenditures in the Appalachian region, and included $27.5 million in the Marcellus Shale area and $90.9 million in the Utica Shale area. These amounts included approximately $34.6 million spent to develop proved undeveloped reserves.
The Exploration and Production segment capital expenditures for the three months ended December 31, 2023 were primarily well drilling and completion expenditures in the Appalachian region, and included $37.5 million in the Marcellus Shale area and $120.2 million in the Utica Shale area. These amounts included approximately $106.0 million spent to develop proved undeveloped reserves.
Pipeline and Storage
The Pipeline and Storage segment capital expenditures for the three months ended December 31, 2024 and December 31, 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.
In addition, due to the continuing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia, specifically in the Marcellus and Utica Shale producing areas, Supply Corporation and Empire have completed and continue to pursue expansion projects designed to move anticipated Marcellus and Utica production gas to other interstate pipelines and to on-system markets, and markets beyond the Supply Corporation and Empire pipeline systems. An expansion and modernization project where the Company has forecasted a significant amount of investment in preliminary survey and investigation costs and/or capital expenditures, and where a precedent agreement has been executed, is discussed below.
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Supply Corporation concluded an Open Season on August 25, 2023, and based on post-open season discussions, has designed a project that would allow for the transportation of 190,000 Dth per day of shale gas supplies from a new interconnection in northwest Tioga County, Pennsylvania to an existing Supply Corporation interconnection with Tennessee Gas Pipeline Company, LLC at Ellisburg and a new virtual delivery point into an existing Transcontinental Gas Pipe Line Company, LLC (“Transco”) capacity lease, providing access to Mid-Atlantic markets (“Tioga Pathway Project”). The Tioga Pathway Project involves the construction of approximately 19 miles of new pipeline and the replacement of approximately four miles of existing pipeline on the Supply Corporation system. Supply Corporation has executed a Precedent Agreement with Seneca for 190,000 Dth per day of transportation capacity and filed a Section 7(c) application with the FERC on August 21, 2024. The Tioga Pathway Project has a projected in-service date of late calendar year 2026 and an estimated capital cost of approximately $101 million. As of December 31, 2024, approximately $3.2 million has been spent to study this project, all of which has been included in Deferred Charges on the Consolidated Balance Sheet at December 31, 2024.
Gathering
The majority of the Gathering segment capital expenditures for the three months ended December 31, 2024 included expenditures related to the continued expansion of Midstream Company's Tioga gathering system. These expenditures were largely attributable to the installation of new in-field gathering pipelines related to bringing new development online and system optimization, as well as the continued development of centralized station facilities, including increased dehydration capacity and compression horsepower.
The majority of the Gathering segment capital expenditures for the three months ended December 31, 2023 included expenditures related to the continued expansion of Midstream Company's Tioga and Clermont gathering systems. These expenditures were largely attributable to the installation of new in-field gathering pipelines related to bringing new development online, as well as the continued development of centralized station facilities, including increased dehydration capacity and compression horsepower.
Utility
The majority of the Utility segment capital expenditures for the three months ended December 31, 2024 and December 31, 2023 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.
Project Funding
During the quarter ended December 31, 2024 and fiscal 2024, the Company has been financing capital expenditures 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 and base rate 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, accelerated development of existing natural gas properties, natural gas storage and transmission facilities, natural gas generation 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 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 $109.3 million when comparing the balance sheet at December 31, 2024 to the balance sheet at September 30, 2024. The maximum amount of short-term debt outstanding during the three months ended December 31, 2024 was $253.9 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
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gas costs, margin calls on derivative financial instruments, repurchases of stock, 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. As of December 31, 2024, the Company had outstanding commercial paper of $200.0 million and did not have any short-term notes payable to banks as of December 31, 2024.
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 provided a $1.0 billion unsecured committed revolving credit facility with a maturity date of February 26, 2027. In February 2024, the Company and eleven of the banks in the syndicate consented to a one-year extension of the maturity date of the Credit Agreement, from February 26, 2027 to February 25, 2028. In May 2024, three of the banks in the syndicate assumed the commitments of the sole non-extending lender. In January 2025, the Company and the eleven banks in the syndicate consented to a second one-year extension of the maturity date, from February 25, 2028 to February 23, 2029, such that the Company has aggregate commitments available under the Credit Agreement in the full amount of $1.0 billion through February 23, 2029.
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. 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.
On February 14, 2024, the Company entered into a Term Loan Agreement (the “Term Loan Agreement”) with six lenders, all of which are lenders under the Credit Agreement. The Term Loan Agreement provides a $300.0 million unsecured committed delayed draw term loan facility with a maturity date of February 14, 2026, and the Company has the ability to select interest periods of one, three or six months for borrowings. In April 2024, pursuant to the delayed draw mechanism, the Company elected to draw a total of $300.0 million under the facility. After deducting debt issuance costs, the net proceeds to the Company amounted to $299.4 million. The Company used the proceeds for general corporate purposes, which included the redemption of outstanding commercial paper. Borrowings under the Term Loan Agreement currently bear interest at a rate equal to SOFR for the applicable interest period, plus an adjustment of 0.10%, plus a spread of 1.375%. The current locked-in interest rate is 5.78% until February 2025.
Both the Credit Agreement and the Term Loan Agreement provide 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 that date, the Company recorded non-cash, after-tax ceiling test impairments totaling $797.0 million. As a result, at December 31, 2024, $398.5 million was added back to the Company's total capitalization for purposes of calculating the debt to capitalization ratio under the Credit Agreement and the Term Loan Agreement. In addition, for purposes of calculating the debt to capitalization ratio, the following amounts included in Accumulated Other Comprehensive Income (Loss) on the Company's consolidated balance sheet will be excluded from the determination of comprehensive shareholders’ equity: 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. As a result of these exclusions, such unrealized gains or losses will not positively or negatively affect the calculation of the debt to capitalization ratio. At December 31, 2024, the Company’s debt to capitalization ratio, as calculated under the agreements, was 0.48. The constraints specified in the Credit Agreement and the Term Loan Agreement would have permitted an additional $2.97 billion in short-term and/or long-term debt to be outstanding at December 31, 2024 (further limited by the indenture covenants discussed below) 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 and the Term Loan Agreement each contain a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement or Term Loan Agreement, as applicable. In particular, a repayment obligation could be triggered if (i) the
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Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $40.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity.
The Current Portion of Long-Term Debt at December 31, 2024 and September 30, 2024 consisted of $50.0 million of 7.38% notes that mature in June 2025 and $450.0 million of 5.20% notes that mature in July 2025.
The Company’s embedded cost of long-term debt was 4.83% at December 31, 2024 and 4.69% at December 31, 2023.
The Company's present liquidity position is believed to be adequate to satisfy known demands. Under the Company’s 1974 indenture, certain covenants exist that, from time to time, may preclude the Company from issuing incremental long-term debt. Given the impairments of exploration and production properties the Company recognized since June 30, 2024, the indenture covenants preclude the Company from issuing incremental long-term debt from January 1, 2025 to June 13, 2025, the maturity date of the Company's remaining indebtedness outstanding under the 1974 indenture.
As of December 31 2024, the Company had $50.0 million in principal and $3.2 million in interest payments remaining related to long-term debt issued under the 1974 indenture. To the extent the Company wishes to relieve its obligations to comply with the 1974 indenture's restrictions, the Company expects to be able to place future principal and interest payments in trust for the benefit of bondholders pursuant to the terms of the 1974 indenture. Depositing such future principal and interest payments in trust would effectively relieve the Company from its obligations to comply with the 1974 indenture’s restrictions, including those on the issuance of incremental long-term debt.
In addition to the covenants noted above, the Company’s 1974 indenture 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.
On March 8, 2024, the Company’s Board of Directors authorized the Company to implement a share repurchase program, whereby the Company may repurchase outstanding shares of common stock, up to an aggregate amount of $200 million in the open market or through privately negotiated transactions, including through the use of trading plans intended to qualify under SEC Rule 10b5-1, in accordance with applicable securities laws and other restrictions. While the program has no fixed expiration date, the Company is targeting completion of this program by the end of fiscal 2025, depending on a number of factors, including but not limited to stock price, market conditions, applicable securities laws, including SEC Rule 10b-18, corporate and regulatory requirements, and capital and liquidity needs. The Company’s Board of Directors may suspend, discontinue, terminate, modify, cancel or extend the share repurchase program at any time and for any reason. During the three months ended December 31, 2024, the Company executed transactions to repurchase 548,596 shares at an average price of $61.27 per share. With broker fees and excise taxes, the total cost of these repurchases amounted to $33.9 million. Share repurchases that settled during the three months ended December 31, 2024 were funded with cash provided by operating activities and/or short-term borrowings. As of December 31, 2024, the Company has repurchased 1,694,855 shares under the share repurchase program at an average price of $57.93, for a total cost of $99.1 million (including broker fees and excise taxes). It is expected that future repurchases, if any, under this program will continue to be funded with cash provided by operating activities and/or through the use of short-term borrowings.
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.
The Company did not make any contributions to its tax-qualified, noncontributory defined benefit retirement plan (Retirement Plan) during the three months ended December 31, 2024, and does not anticipate making any such contributions during the remainder of fiscal 2025. The Company also did not make any contributions to its VEBA trusts for its other post-
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retirement benefits during the three months ended December 31, 2024, and does not anticipate making any such contributions during the remainder of fiscal 2025.
Market Risk Sensitive Instruments
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 authoritative guidance for fair value measurements and disclosures requires consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At December 31, 2024, 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 2024 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.” 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 York Jurisdiction
Distribution Corporation's current delivery rates in its New York jurisdiction were approved by the NYPSC in an order issued on December 19, 2024 with rates effective January 1, 2025 (“2024 Rate Order”). The 2024 Rate Order authorizes a three-year rate plan effective October 1, 2024, with a make-whole provision allowing full recovery of revenues that would have been billed at the new rates between October 1, 2024 and December 31, 2024. It also reflects a return on equity of 9.7% and authorizes a revenue requirement increase of $57.3 million in fiscal 2025, an additional revenue requirement increase of $15.8 million in fiscal 2026, and an additional revenue requirement increase of $12.7 million in fiscal 2027. The revenue requirement for each year of the three-year plan has been reduced by $14 million for actuarial projections of income that is expected to be recognized for qualified pension and other post-retirement benefits. Qualified pension and other post-retirement benefit income or costs are matched with amounts included in revenue resulting in zero impact to earnings. The 2024 Rate Order approves the continuation of several ratemaking mechanisms, including revenue decoupling and WNA, and establishes a number of new cost trackers and regulatory deferrals. It also includes an earnings sharing mechanism, gas safety and customer service performance metrics (including maintaining the Company’s leak prone pipe replacement program), and provisions that will facilitate achievement of the emissions reduction goals of the CLCPA.
Pennsylvania Jurisdiction
Distribution Corporation’s current delivery rates in its Pennsylvania jurisdiction were approved by the PaPUC in an order issued on June 15, 2023 with rates effective August 1, 2023 (“2023 Rate Order”). The 2023 Rate Order provided for, among other things, an increase in Distribution Corporation’s annual base rate operating revenues of $23 million and authorized a new weather normalization adjustment mechanism.
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On April 10, 2024, Distribution Corporation filed with the PaPUC a petition for approval of a distribution system improvement charge (“DSIC”) to recover, between base rate cases, capital expenses related to eligible property constructed or installed to rehabilitate, improve and replace portions of the Company’s natural gas distribution system. The DSIC petition was approved by the PaPUC on December 5, 2024, and on January 1, 2025, the Company initiated recovery of eligible costs on incremental rate base added after September 30, 2024.
Pipeline and Storage
Supply Corporation's rate settlement, approved June 11, 2024, provides that Supply Corporation may make a rate filing for new rates to be effective at any time. As well, any party can make a filing under NGA Section 5. Supply Corporation has no rate case currently on file.
Empire's 2019 rate settlement requires a Section 4 rate case filing no later than May 1, 2025. Empire is not barred from filing a Section 4 rate case before the May 1, 2025 date. Empire has no rate case currently on file.
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 be impacted as environmental exposures, technology and opportunities change and regulatory and policy updates are issued.
For further discussion of the Company's environmental exposures, refer to Item 1 at Note 7 – 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, and executive orders 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, cap and invest and cap and trade programs, restrictive permitting, increased efficiency standards, and incentives or mandates to conserve energy or use renewable energy sources. For example, the federal Inflation Reduction Act of 2022 (IRA) legislation was signed into law on August 16, 2022, and includes a directive for the EPA, the lead federal agency that regulates greenhouse gas emissions pursuant to the Clean Air Act, to develop a waste emissions charge (WEC) applicable to the reported annual methane emissions of certain oil and gas facilities, above specified methane intensity thresholds. EPA published its final WEC regulations in November 2024. EPA regulations also impose stringent leak detection and repair requirements and address reporting and control of methane and volatile organic compound emissions, which were further expanded with EPA’s March 2024 publication and finalization of the Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources and its May 2024 finalization of the Greenhouse Gas Reporting Program, Part 98 - Subpart W Final Rule.
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. 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 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. The NYPSC has initiated and/or modified various proceedings in an effort to help the State meet these emissions reduction targets. 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. The NYDEC, in conjunction with the New York State Energy Research and Development Authority, is developing a cap-and-invest program in the state. The above-enumerated
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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 reduce demand for natural gas and 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. Impairments under the SEC's full cost ceiling test for natural gas reserves;
2. Changes in the price of natural gas;
3. 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;
4. 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;
5. The Company’s ability to estimate accurately the time and resources necessary to meet emissions targets;
6. Governmental/regulatory actions and/or market pressures to reduce or eliminate reliance on natural gas;
7. 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;
8. The creditworthiness or performance of the Company’s key suppliers, customers and counterparties;
9. Financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments,
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including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions;
10. 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;
11. The impact of information technology disruptions, cybersecurity or data security breaches;
12. 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, water availability and disposal or recycling opportunities of used water, 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;
13. The Company's ability to complete strategic transactions;
14. 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;
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.
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