National Fuel Gas Co.
07/30/2026 | Press release | Distributed by Public on 07/30/2026 09:54
Quarterly Report for Quarter Ending June 30, 2026 (Form 10-Q)
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
Table of Content
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 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 three 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 in northwest Tioga County, Pennsylvania. On May 5, 2025, FERC issued the Section 7(b)/7(c) certificate for the project and on January 8, 2026, FERC issued the Notice to Proceed with Construction. Construction on the Tioga Pathway Project commenced in February 2026. This project has a target in-service date in late calendar 2026.
Supply Corporation has also announced that it expects to serve as the transporter of 205,000 Dth per day of natural gas supplies to the Shippingport Power Station site in Beaver County, Pennsylvania, which will support a co-located data center that is currently under development. The project obtained FERC authorization under the Commission's prior notice regulations on November 7, 2025 and construction commenced in March 2026.
Supply Corporation has also developed its Line N System Upgrade Project, which will consist of modernization of primarily 1960's era pipeline in Beaver County, Pennsylvania, as well as minor compressor station and facility upgrades, to create approximately 294,000 Dth per day of additional natural gas transportation capacity (1) from a new interconnection on the southern portion of Supply Corporation's Line N system in Greene County, Pennsylvania to an existing Supply Corporation interconnection with Tennessee Gas Pipeline Company, LLC at Mercer and (2) from an existing Supply Corporation interconnection with Texas Eastern Transmission, LP at Holbrook to a new interconnection at the Shippingport Industrial Park in Shippingport, Pennsylvania. Supply Corporation executed long-term precedent agreements with two shippers for 100% of the incremental capacity created by the project. The project has a projected in-service date of late calendar 2028. The Tioga Pathway Project, Shippingport Lateral Project and Line N System Upgrade Project are all 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, established a three-year rate plan that reflects a return on equity of 9.7% and authorized 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 included 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, on May 5, 2026, Distribution Corporation filed a petition with the NYPSC for authorization to implement a system modernization tracker reconciliation mechanism through which qualified leak prone pipe removal costs incurred by the Company would be tracked and recovered. The petition remains pending with the Commission.
In Distribution Corporation's Pennsylvania jurisdiction, Distribution Corporation made a filing with the PaPUC on January 28, 2026 seeking an increase in its annual base rate operating revenues of $19.7 million with a proposed effective date of March 29, 2026. The Company is proposing, among other things, a new residential energy efficiency pilot program and to make permanent its weather normalization adjustment mechanism. The Company is also proposing reactivation of the OPEB surcredit to refund $7.2 million for customer bill relief. As reflected in a February 19, 2026 PaPUC Order, the filing was suspended until October 29, 2026 by operation of law unless directed otherwise by the PaPUC. Final briefs were submitted in the case on July 1, 2026. A decision is generally anticipated from the administrative law judge in August 2026.
Supply Corporation filed an NGA Section 4 rate case at FERC on April 30, 2026 proposing rate increases to be effective November 1, 2026. Supply Corporation's filing requests an annual cost of service of approximately $404 million, an increase of approximately $95 million from Supply Corporation's settlement of its 2023 rate proceeding. By regulation, the proposed rates will become effective November 1, 2026 subject to refund, unless the parties in the case reach a settlement. In addition, on March 17, 2025, FERC approved an amendment to Empire's 2019 rate case settlement. This settlement amendment is estimated to decrease Empire's revenues on a yearly basis by approximately $0.5 million. For further discussion of these and other rate matters, refer to the Rate Matters section below.
Table of Content
On October 20, 2025, the Company entered into the Purchase Agreement with CenterPoint Energy Resources Corp. (the "Seller"), pursuant to which, among other things, the Company agreed to acquire from the Seller all of the issued and outstanding equity interests of CenterPoint Ohio for an aggregate purchase price of $2.62 billion, subject to customary adjustments, as provided in the Purchase Agreement. This acquisition will add significant regulated scale for the Company, doubling the size of the Company's gas utility rate base, while expanding its operations beyond New York and Pennsylvania into the neighboring state of Ohio, a state with a constructive regulatory and political environment that is supportive of natural gas. Closing is expected to occur on October 1, 2026. The purchase price will include a combination of $1.42 billion in cash and a $1.2 billion promissory note to be issued by the Company to the Seller at closing. The promissory note, which was part of the Seller's desired transaction structure and was incorporated into the Company's business valuation, will have a maturity date of 364 days post-closing and will carry an interest rate of 6.5%. Permanent financing, inclusive of the amount to repay the promissory note, is expected to consist of long-term debt and common equity, along with expected future free cash flow. In that regard, on December 17, 2025, the Company completed the issuance and sale, in a private placement, of 4,402,513 shares of the Company's common stock, par value $1.00 per share, at a price of $79.50 per share. After deducting placement fees, the net proceeds to the Company amounted to $338.4 million. Furthermore, as discussed in Note 7 - Capitalization, the Company issued $1.5 billion of long-term debt on June 10, 2026. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $1,481.2 million. After redeeming certain notes scheduled to mature on October 1, 2026 with a portion of the net proceeds, the Company invested the remaining net proceeds from the debt issuance in temporary cash investments and expects to use that cash to fund a substantial portion of the purchase price at closing.
In connection with the Purchase Agreement, the Company entered into commitment letters for a 364-day senior unsecured term loan facility related to the consideration to be paid at closing, and a senior unsecured bridge loan facility related to repayment of the promissory note. The commitment letters are supported by the Commitment Parties and additional banks, all of which are lenders under the Company's primary credit facility. The combination of both facilities was designed to fully support any portion of the purchase price that had not been permanently financed. Given the permanent financing in place, as mentioned in the previous paragraph, the Company terminated the 364-day term loan facility commitment letter effective June 10, 2026. The remaining commitment under the senior unsecured bridge loan facility commitment letter is currently $1.10 billion.
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. The Company recorded a non-cash impairment charge under the ceiling test during the quarter ended December 31, 2024 of $108.3 million ($79.1 million after-tax). At June 30, 2026, the ceiling exceeded the book value of the exploration and production properties, and thus, did not result in an impairment charge in the quarter ended June 30, 2026. Please refer to the Critical Accounting Estimates section below for more details on this matter and a sensitivity analysis concerning commodity price changes.
On March 27, 2026, the Company entered into an Amended and Restated Credit Agreement (the "Credit Agreement") with PNC Bank, National Association, as administrative agent and lender, and 12 additional lenders. The Credit Agreement provides a $1.3 billion unsecured committed revolving credit facility with an initial maturity date of March 27, 2031. For further discussion of the Credit Agreement, refer to the Capital Resources and Liquidity section below.
The Company expects to use cash from operations and short-term borrowings, as needed, to meet its financing needs for the remainder of fiscal 2026. 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 the ongoing impacts of federal policy changes, 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 2025 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 Integrated Upstream and Gathering segment, follows the full cost method of accounting for determining the book value of its 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
Table of Content
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. At June 30, 2026, the ceiling exceeded the book value of the exploration and production properties by approximately $1.4 billion (after-tax). 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, 2026, based on the quoted Henry Hub spot price for natural gas, was $3.64 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, 2026. 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 in the twelve-month period used at June 30, 2026 in the ceiling test calculation, the ceiling would have exceeded the book value of the Company's exploration and production properties by approximately $1.0 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 "Exploration and Development Costs" under "Critical Accounting Estimates" in Item 7 of the Company's 2025 Form 10-K.
RESULTS OF OPERATIONS
Earnings
The Company's earnings were $138.6 million for the quarter ended June 30, 2026 compared to earnings of $149.8 million for the quarter ended June 30, 2025. The decrease in earnings of $11.2 million is primarily the result of a loss in the Corporate category and lower earnings in the Integrated Upstream and Gathering segment.
The Company's earnings were $567.9 million for the nine months ended June 30, 2026 compared to earnings of $411.2 million for the nine months ended June 30, 2025. The increase in earnings of $156.7 million is primarily the result of higher earnings in the Integrated Upstream and Gathering segment.
The Company's earnings for the nine months ended June 30, 2025 included non-cash impairment charges of $141.8 million ($103.6 million after-tax) in the Integrated Upstream and Gathering 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 June 30, |
Nine Months Ended June 30, |
|||||||||||||||||||
| (Thousands) | 2026 | 2025 |
Increase (Decrease) |
2026 | 2025 |
Increase (Decrease) |
||||||||||||||
| Integrated Upstream and Gathering | $ | 111,874 | $ | 116,667 | $ | (4,793) | $ | 387,951 | $ | 221,205 | $ | 166,746 | ||||||||
| Pipeline and Storage | 28,739 | 28,857 | (118) | 91,565 | 93,019 | (1,454) | ||||||||||||||
| Utility | 5,686 | 4,997 | 689 | 105,125 | 101,040 | 4,085 | ||||||||||||||
| Total Reportable Segments | 146,299 | 150,521 | (4,222) | 584,641 | 415,264 | 169,377 | ||||||||||||||
| All Other | (222) | (209) | (13) | 523 | (674) | 1,197 | ||||||||||||||
| Corporate | (7,456) | (494) | (6,962) | (17,230) | (3,428) | (13,802) | ||||||||||||||
| Total Consolidated | $ | 138,621 | $ | 149,818 | $ | (11,197) | $ | 567,934 | $ | 411,162 | $ | 156,772 | ||||||||
Table of Content
Integrated Upstream and Gathering
Integrated Upstream and Gathering Operating Revenues
|
Three Months Ended June 30, |
Nine Months Ended June 30, |
|||||||||||||||||||
| (Thousands) | 2026 | 2025 |
Increase (Decrease) |
2026 | 2025 |
Increase (Decrease) |
||||||||||||||
| Gas Produced in Appalachia (after Hedging) | $ | 293,294 | $ | 302,652 | $ | (9,358) | $ | 960,672 | $ | 860,409 | $ | 100,263 | ||||||||
| Gathering | 3,723 | 2,519 | 1,204 | 9,113 | 9,200 | (87) | ||||||||||||||
| Other | 5,499 | 1,231 | 4,268 | 14,776 | 4,292 | 10,484 | ||||||||||||||
| $ | 302,516 | $ | 306,402 | $ | (3,886) | $ | 984,561 | $ | 873,901 | $ | 110,660 | |||||||||
Production Volumes
|
Three Months Ended June 30, |
Nine Months Ended June 30, |
|||||||||||||||||||
| 2026 | 2025 |
Increase (Decrease) |
2026 | 2025 |
Increase (Decrease) |
|||||||||||||||
| Gas Production (MMcf) | 104,285 | 111,588 | (7,303) | 315,470 | 314,819 | 651 | ||||||||||||||
Average Prices
|
Three Months Ended June 30, |
Nine Months Ended June 30, |
|||||||||||||||||||
| 2026 | 2025 |
Increase (Decrease) |
2026 | 2025 |
Increase (Decrease) |
|||||||||||||||
| Average Gas Price/Mcf | ||||||||||||||||||||
| Weighted Average | $ | 2.25 | $ | 2.69 | $ | (0.44) | $ | 2.97 | $ | 2.66 | $ | 0.31 | ||||||||
| Weighted Average After Hedging | $ | 2.81 | $ | 2.71 | $ | 0.10 | $ | 3.05 | $ | 2.73 | $ | 0.32 | ||||||||
2026 Compared with 2025
Operating revenues for the Integrated Upstream and Gathering segment decreased $3.9 million for the quarter ended June 30, 2026 as compared with the quarter ended June 30, 2025. Gas production revenue after hedging decreased $9.4 million due to the impact of a 7.3 Bcf decrease in natural gas production, offset by a $0.10 per Mcf increase in the weighted average price of natural gas after hedging. The decrease in natural gas production was largely due to natural declines on producing wells, partially offset by production from recently turned-in-line wells. Other revenue increased $4.3 million primarily due to changes in segment reporting. The change in segment reporting is fully offset in other operating expenses. Gathering revenue also increased $1.2 million, primarily due to insurance proceeds received during the period.
Operating revenues for the Integrated Upstream and Gathering segment increased $110.7 million for the nine months ended June 30, 2026 as compared with the nine months ended June 30, 2025. Gas production revenue after hedging increased $100.3 million due to the impact of a $0.32 per Mcf increase in the weighted average price of natural gas after hedging, coupled with a 0.7 Bcf increase in natural gas production. The increase in natural gas production was largely due to the timing of new wells brought online, partially offset by production declines on producing wells. In addition, other revenue increased $10.5 million primarily due to changes in segment reporting. The change in segment reporting is fully offset in other operating expenses.
The Integrated Upstream and Gathering segment's earnings for the quarter ended June 30, 2026 were $111.9 million, a decrease of $4.8 million when compared with earnings of $116.7 million for the quarter ended June 30, 2025. The $4.8 million decrease can be attributed to the following factors:
Table of Content
| (Millions) | |||||||||||
| Higher natural gas prices after hedging | $ | 8.3 | |||||||||
| Higher other revenue | 3.8 | ||||||||||
| Lower interest expense | 3.7 |
(1)
|
|||||||||
| Lower income tax expense | 2.1 |
(2)
|
|||||||||
| Lower other tax expense | 1.1 |
(3)
|
|||||||||
| Higher gathering revenue | 1.0 | ||||||||||
| Lower natural gas production | (15.6) | ||||||||||
| Higher other operating expenses | (3.3) |
(4)
|
|||||||||
| Higher depletion expense | (2.7) |
(5)
|
|||||||||
| Higher lease operating expense | (2.6) |
(6)
|
|||||||||
| Other items | (0.6) | ||||||||||
| $ | (4.8) | ||||||||||
(1)The decrease in interest expense was mainly attributed to lower short-term and long-term intercompany borrowings.
(2)The decrease in income tax expense was primarily driven by lower pre-tax income.
(3)The decrease in other tax expense was primarily attributable to fewer wells subject to the Impact Fee during the period.
(4)The increase in other operating expenses was mainly attributed to a change in segment reporting combined with higher gathering operation and maintenance expenses. These were partially offset by lower personnel costs.
(5)The increase in depletion was primarily due to a lower depletion rate in the prior year third quarter as a result of the ceiling test impairments recorded in the third and fourth quarters of fiscal 2024 as well as the first quarter of fiscal 2025 that lowered Seneca's full cost pool depletable base.
(6)The increase in lease operating expense was mainly attributed to higher third party gathering and transportation costs combined with higher repairs, offset by lower workovers.
The Integrated Upstream and Gathering segment's earnings for the nine months ended June 30, 2026 were $388.0 million, an increase of $166.8 million when compared with earnings of $221.2 million for the nine months ended June 30, 2025. The $166.8 million increase can be attributed to the following factors:
| (Millions) | |||||||||||
| Prior period's impairment of assets | $ | 103.6 |
(1)
|
||||||||
| Higher natural gas prices after hedging | 77.8 | ||||||||||
| Lower interest expense | 10.5 |
(2)
|
|||||||||
| Higher other operating revenue | 8.9 | ||||||||||
| Lower premiums paid on early redemption of debt | 1.4 |
(3)
|
|||||||||
| Higher natural gas production | 1.4 | ||||||||||
| Earnings impact associated with remeasurement of state deferred income taxes due to ceiling test impairments | 1.0 |
(4)
|
|||||||||
| Higher depletion expense | (14.9) |
(5)
|
|||||||||
| Higher lease operating expense | (11.3) |
(6)
|
|||||||||
| Higher other operating expenses | (9.1) |
(7)
|
|||||||||
| Higher income tax expense | (2.3) |
(8)
|
|||||||||
| Other items | (0.2) | ||||||||||
| $ | 166.8 | ||||||||||
(1)Includes a ceiling test impairment of $79.1 million and a $24.5 million impairment of certain water disposal assets recorded during the quarter ended December 31, 2024.
(2)The decrease in interest expense was mainly attributed to lower short-term and long-term intercompany borrowings.
(3)Represents the segment's share of premiums incurred in connection with the Company's redemption of long-term debt during the nine months ended June 30, 2025, partially offset by premiums incurred on a long-term debt redemption during the nine months ended June 30, 2026.
Table of Content
(4)The increase was due to a $1.0 million earnings reduction associated with the remeasurement of state deferred income taxes for the nine months ended June 30, 2025.
(5)The increase in depletion was primarily due to a lower depletion rate in the prior year nine-month period as a result of ceiling test impairments recorded in the third and fourth quarters of fiscal 2024 as well as the first quarter of fiscal 2025 that lowered Seneca's full cost pool depletable base.
(6)The increase in lease operating expense was primarily the result of additional third-party gathering and transportation costs combined with higher road maintenance and repair costs.
(7)The increase in other operating expenses was mainly attributed to a change in segment reporting combined with higher gathering operation and maintenance and higher abandonment accretion expense. These were partially offset by lower abandonment costs recognized during the nine months ended June 30, 2026 and lower personnel costs.
(8)The increase in income tax expense was primarily driven by higher state tax expense due to an increase in pre-tax income.
Pipeline and Storage
Pipeline and Storage Operating Revenues
|
Three Months Ended June 30, |
Nine Months Ended June 30, |
|||||||||||||||||||
| (Thousands) | 2026 | 2025 |
Increase (Decrease) |
2026 | 2025 |
Increase (Decrease) |
||||||||||||||
| Firm Transportation | $ | 80,704 | $ | 80,078 | $ | 626 | $ | 244,336 | $ | 243,388 | $ | 948 | ||||||||
| Interruptible Transportation | 163 | 157 | 6 | 587 | 533 | 54 | ||||||||||||||
| 80,867 | 80,235 | 632 | 244,923 | 243,921 | 1,002 | |||||||||||||||
| Firm Storage Service | 25,699 | 25,028 | 671 | 76,513 | 75,309 | 1,204 | ||||||||||||||
| Other | (25) | 316 | (341) | 3,469 | 2,535 | 934 | ||||||||||||||
| $ | 106,541 | $ | 105,579 | $ | 962 | $ | 324,905 | $ | 321,765 | $ | 3,140 | |||||||||
Pipeline and Storage Throughput
|
Three Months Ended June 30, |
Nine Months Ended June 30, |
|||||||||||||||||||
| (MMcf) | 2026 | 2025 |
Increase (Decrease) |
2026 | 2025 |
Increase (Decrease) |
||||||||||||||
| Firm Transportation | 179,348 | 179,033 | 315 | 640,367 | 616,644 | 23,723 | ||||||||||||||
| Interruptible Transportation | 935 | 149 | 786 | 1,543 | 665 | 878 | ||||||||||||||
| 180,283 | 179,182 | 1,101 | 641,910 | 617,309 | 24,601 | |||||||||||||||
2026 Compared with 2025
Operating revenues for the Pipeline and Storage segment increased $1.0 million for the quarter ended June 30, 2026 as compared with the quarter ended June 30, 2025. The increase in operating revenue was primarily driven by an increase in storage revenues of $0.7 million and an increase in transportation revenues of $0.6 million, partially offset by lower other revenues of $0.3 million. The increase in storage revenues was primarily attributable to remarketed capacity that became available through customer contract negotiations and rate increases on existing contracts, partially offset by revisions to existing contracts. The increase in transportation revenues primarily reflects an adjustment to match electric surcharge revenues with electric power costs recorded in operation and maintenance expense and rate increases on existing contracts, partially offset by revisions to existing contracts.
Operating revenues for the Pipeline and Storage segment increased $3.1 million for the nine months ended June 30, 2026 as compared with the nine months ended June 30, 2025. The increase in operating revenue was primarily driven by an increase in storage revenues of $1.2 million and an increase in transportation revenues of $1.0 million, along with higher other revenues of $0.9 million. The increase in storage revenues was primarily attributable to remarketed capacity from customer contract negotiations, higher rates and deliverability enhancements on existing contracts, and increased commodity revenue driven by colder weather, partially offset by contract revisions. The increase in transportation revenues was primarily attributable to new long-term contracts, rate increases on existing contracts and an adjustment to match electric surcharge revenues with electric power costs recorded in operation and maintenance expense, partially offset by revisions to existing
Table of Content
contracts. The increase in other revenues primarily reflects an adjustment to match electric surcharge revenues with electric power costs recorded in operation and maintenance expense mentioned above.
Transportation volume for the quarter and nine months ended June 30, 2026 increased by 1.1 Bcf and 24.6 Bcf, respectively, from the prior year's quarter and nine month periods. The increase in transportation volume for the quarter ended June 30, 2026 is primarily driven by a modest increase in shipper demand. The increase in transportation volume for the nine months ended June 30, 2026 is primarily due to increased utilization resulting from colder weather, as well as an increase in shipper demand. 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, 2026 were $28.7 million, a decrease of $0.2 million when compared with earnings of $28.9 million for the quarter ended June 30, 2025. The $0.2 million decrease can be attributed to the following factors:
| (Millions) | |||||||||||
| Higher operating expenses | $ | (1.0) |
(1)
|
||||||||
| Higher depreciation expense | (0.8) |
(2)
|
|||||||||
| Higher operating revenues | 0.8 | ||||||||||
| Higher other income | 0.6 |
(3)
|
|||||||||
| Lower income tax expense | 0.6 |
(4)
|
|||||||||
| Other items | (0.4) | ||||||||||
| $ | (0.2) | ||||||||||
(1)The increase in operating expense is primarily due to an increase in outside service expenses, largely related to system maintenance spending. Additionally, the increase was driven by higher power costs related to Empire's electric motor drive compressor station. The increase in electric power costs is offset by an equal increase in revenue.
(2)The increase in depreciation expense primarily reflects additional plant in-service.
(3)The increase in other income is primarily due to an increase in allowance for funds used during construction ("AFUDC") related to the construction of the Tioga Pathway and Shippingport Lateral projects as well as changes in the AFUDC capitalization rate.
(4)The decrease in income tax expense is primarily attributable to a change in state apportionment factors used in the current year when compared to the prior year, along with a decrease in Pennsylvania state income tax rates in the current year.
The Pipeline and Storage segment's earnings for the nine months ended June 30, 2026 were $91.6 million, a decrease of $1.4 million when compared with earnings of $93.0 million for the nine months ended June 30, 2025. The $1.4 million decrease can be attributed to the following factors:
| (Millions) | |||||||||||
| Higher operating revenues | $ | 2.5 | |||||||||
| Lower income tax expense | 1.1 |
(1)
|
|||||||||
| Higher depreciation expense | (2.4) |
(2)
|
|||||||||
| Higher operating expenses | (1.6) |
(3)
|
|||||||||
| Lower other income | (1.1) |
(4)
|
|||||||||
| Other items | 0.1 | ||||||||||
| $ | (1.4) | ||||||||||
(1)The decrease in income tax expense is primarily attributable to a change in state apportionment factors used in the current year when compared to the prior year, along with a decrease in Pennsylvania state income tax rates in the current year.
(2)The increase in depreciation expense primarily reflects additional plant in-service.
(3)The increase in operating expense is primarily due to higher power costs related to Empire's electric motor drive compressor station. Partially offsetting these costs was a decrease in outside service expenses, largely driven by lower storage well re-plugging costs and preventative maintenance as well as a decrease in personnel costs. The increase in electric power costs is offset by an equal increase in revenue.
Table of Content
(4)The decrease in other income was primarily due to a lower average amount outstanding on intercompany short-term notes receivables and a lower weighted average interest rate on those receivables, partially offset by an increase in AFUDC related to the construction of the Tioga Pathway and Shippingport Lateral projects as well as changes in the AFUDC capitalization rate.
Utility
Utility Operating Revenues
|
Three Months Ended June 30, |
Nine Months Ended June 30, |
|||||||||||||||||||
| (Thousands) | 2026 | 2025 |
Increase (Decrease) |
2026 | 2025 |
Increase (Decrease) |
||||||||||||||
| Retail Sales Revenues: | ||||||||||||||||||||
| Residential | $ | 126,498 | $ | 118,819 | $ | 7,679 | $ | 645,473 | $ | 546,841 | $ | 98,632 | ||||||||
| Commercial | 13,992 | 14,283 | (291) | 89,151 | 75,112 | 14,039 | ||||||||||||||
| Industrial | 895 | 735 | 160 | 4,830 | 4,030 | 800 | ||||||||||||||
| 141,385 | 133,837 | 7,548 | 739,454 | 625,983 | 113,471 | |||||||||||||||
| Transportation | 21,242 | 21,577 | (335) | 101,365 | 96,979 | 4,386 | ||||||||||||||
| Other | 2,873 | 2,109 | 764 | 9,733 | 6,762 | 2,971 | ||||||||||||||
| $ | 165,500 | $ | 157,523 | $ | 7,977 | $ | 850,552 | $ | 729,724 | $ | 120,828 | |||||||||
Utility Throughput
|
Three Months Ended June 30, |
Nine Months Ended June 30, |
|||||||||||||||||||
| (MMcf) | 2026 | 2025 |
Increase (Decrease) |
2026 | 2025 |
Increase (Decrease) |
||||||||||||||
| Retail Sales: | ||||||||||||||||||||
| Residential | 9,253 | 10,151 | (898) | 64,029 | 60,738 | 3,291 | ||||||||||||||
| Commercial | 1,260 | 1,658 | (398) | 10,389 | 9,997 | 392 | ||||||||||||||
| Industrial | 95 | 93 | 2 | 590 | 594 | (4) | ||||||||||||||
| 10,608 | 11,902 | (1,294) | 75,008 | 71,329 | 3,679 | |||||||||||||||
| Transportation | 12,756 | 13,853 | (1,097) | 57,927 | 55,881 | 2,046 | ||||||||||||||
| 23,364 | 25,755 | (2,391) | 132,935 | 127,210 | 5,725 | |||||||||||||||
Degree Days
| Three Months Ended June 30, | Percent Colder (Warmer) Than | ||||||||||||||||
| Normal | 2026 | 2025 |
Normal(1)
|
Prior Year(1)
|
|||||||||||||
| Buffalo, NY | 843 | 797 | 825 | (5.5) | % | (3.4) | % | ||||||||||
| Erie, PA | 776 | 711 | 813 | (8.4) | % | (12.5) | % | ||||||||||
| Nine Months Ended June 30, | |||||||||||||||||
| Buffalo, NY | 6,195 | 6,360 | 5,825 | 2.7 | % | 9.2 | % | ||||||||||
| Erie, PA | 5,693 | 5,911 | 5,527 | 3.8 | % | 6.9 | % | ||||||||||
(1)Percents compare actual 2026 degree days to normal degree days and actual 2026 degree days to actual 2025 degree days.
2026 Compared with 2025
Operating revenues for the Utility segment increased $8.0 million for the quarter ended June 30, 2026 as compared with the quarter ended June 30, 2025. This increase resulted from a $7.5 million increase in retail gas sales revenue and a $0.8 million increase in other revenue, partially offset by a $0.3 million decrease in transportation revenue. The increase in retail gas
Table of Content
sales revenue reflects higher base delivery rates effective October 1, 2025 from the impact of the implementation of year two of Distribution Corporation's three-year rate settlement in its New York jurisdiction. Additional details regarding the base rate regulatory proceeding can be found in the Rate Matters section below. The increase in retail gas sales revenue was partially offset by lower revenues collected from customers for purchased gas costs resulting mainly from a 1.3 Bcf decrease in throughput mainly due to warmer weather, partially offset by a slight increase in the cost of gas sold (per Mcf). 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. Retail gas sales revenue and transportation revenue were also impacted by a $1.2 million increase to revenue from a distribution system improvement charge ("DSIC") modernization tracker in Pennsylvania that became effective in January 2025. For further discussion of the DSIC tracker, refer to the Rate Matters section below. The decrease in transportation revenue was primarily due to a 1.1 Bcf decrease in throughput due primarily to warmer weather, partially offset by increases to revenue from the DSIC tracker discussed above. The increase in other revenue was primarily due to increases in late payment charges billed to customers ($0.4 million) and gains from certain vehicle sales ($0.4 million).
Operating revenues for the Utility segment increased $120.8 million for the nine months ended June 30, 2026 as compared with the nine months ended June 30, 2025. This increase resulted from a $113.5 million increase in retail gas sales revenue, a $4.4 million increase in transportation revenue and a $3.0 million increase in other revenue. The increase in retail gas sales revenue and transportation revenue reflects higher base delivery rates effective October 1, 2025 from the impact of the implementation of year two of Distribution Corporation's three-year rate settlement in its New York jurisdiction, as discussed above. The increase in retail gas sales revenue also reflects higher revenues collected from customers for purchased gas costs resulting from an increase in the cost of gas sold (per Mcf) as well as a 3.7 Bcf increase in throughput mainly due to colder weather. Retail gas sales revenue and transportation revenue were also impacted by a $4.9 million increase to revenue from the DSIC modernization tracker in Pennsylvania, as discussed above. The increase in transportation revenue also reflects a 2.0 Bcf increase in throughput due primarily to colder weather. The increase in other revenue was primarily due to increases in late payment charges billed to customers ($1.3 million) and capacity release revenues ($0.7 million), as well as certain net positive revenue adjustments as a result of operational performance of safety performance measures in accordance with the rate settlement ($0.8 million).
The Utility segment's earnings for the quarter ended June 30, 2026 were $5.7 million, an increase of $0.7 million million when compared with earnings of $5.0 million for the quarter ended June 30, 2025. The increase can be attributed to the following factors:
| (Millions) | |||||||||||
| Impact of new base rates in New York | $ | 4.4 | |||||||||
| Impact of regulatory revenue adjustments | 0.3 |
(1)
|
|||||||||
| Higher operating expenses | (3.6) |
(2)
|
|||||||||
| Impact of lower customer usage | (0.7) | ||||||||||
| Other items | 0.3 | ||||||||||
| $ | 0.7 | ||||||||||
(1)Amount primarily reflects an increase in earnings from a DSIC modernization tracker in Pennsylvania that became effective in January 2025, partially offset by certain other quarterly regulatory true-up adjustments.
(2)The increase in operating expenses is largely attributable to higher uncollectible expenses as a result of higher operating revenue, as well as higher costs for personnel, materials and outside services.
The impact of weather variations on earnings 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 customer bills and earnings for the Utility segment. For the quarter ended June 30, 2026, the WNA preserved earnings of approximately $0.9 million in the Utility segment's New York rate jurisdiction and preserved earnings of approximately $1.0 million in the Utility Segment's Pennsylvania rate jurisdiction, as the weather was warmer than normal on a cycle-bill basis in both jurisdictions. For the quarter ended June 30, 2025, the WNA preserved earnings of approximately $1.3 million in the Utility segment's New York rate jurisdiction and preserved earnings of approximately $0.5 million in the Utility Segment's Pennsylvania rate jurisdiction, as the weather was warmer than normal on a cycle-bill basis in both jurisdictions.
The Utility segment's earnings for the nine months ended June 30, 2026 were $105.1 million, an increase of $4.1 million when compared with earnings of $101.0 million for the nine months ended June 30, 2025. The increase can be attributed to the following factors:
Table of Content
| (Millions) | |||||||||||
| Impact of new base rates in New York | $ | 10.5 | |||||||||
| Impact of regulatory revenue adjustments | 4.9 |
(1)
|
|||||||||
| Higher other operating revenues | 1.9 | ||||||||||
| Impact of higher customer usage | 1.0 | ||||||||||
| Higher operating expenses | (10.3) |
(2)
|
|||||||||
| Higher depreciation expense | (2.6) |
(3)
|
|||||||||
| Higher income tax expense | (1.3) |
(4)
|
|||||||||
| $ | 4.1 | ||||||||||
(1)Amount primarily reflects an increase in earnings from a DSIC modernization tracker in Pennsylvania that became effective in January 2025 combined with certain other quarterly regulatory true-up adjustments.
(2)The increase in operating expenses is largely attributable to higher uncollectible expenses as a result of higher operating revenue, as well as higher costs for personnel, materials and outside services.
(3)The increase in depreciation expense is attributable to higher average property, plant and equipment balances.
(4)The increase in income tax expense is mainly attributed to higher state income tax expense as well as certain provision-to-return adjustments.
For the nine months ended June 30, 2026, the WNA reduced earnings by approximately $1.1 million and $1.0 million, respectively, in the Utility segment's New York and Pennsylvania rate jurisdictions, as the weather was colder than normal on a cycle-bill basis in both jurisdictions. For the nine months ended June 30, 2025, the WNA preserved earnings in the Utility segment's New York rate jurisdiction of approximately $3.9 million and preserved earnings in the Utility segment's Pennsylvania rate jurisdiction of approximately $1.7 million, as the weather was warmer than normal on a cycle-bill basis in both jurisdictions.
ALL OTHER AND CORPORATE OPERATIONS
2026 Compared with 2025
All Other and Corporate operations reported a net loss of $7.7 million for the quarter ended June 30, 2026, an increase of $7.0 million when compared with a net loss of $0.7 million for the quarter ended June 30, 2025. The increase was primarily attributable to external costs incurred to prepare for the integration of CenterPoint Ohio in connection with the Company's planned acquisition ($4.8 million). Additional contributors to the increase were higher operating expenses ($2.5 million) primarily attributable to an increase in internal labor costs, employee benefits and legal and consulting fees, interest expense associated with the June 2026 debt issuances, net of interest benefits related to the investment of proceeds from the debt issuances, that were completed to finance the planned acquisition of CenterPoint Ohio ($0.9 million) and higher income tax expense primarily due to the absence of a federal provision-to-return adjustment benefit recognized in the prior-year period ($0.7 million). This benefit will be recorded in the fourth quarter of the current fiscal year. Partially offsetting these increases to net loss was a net interest benefit arising from the December 2025 equity issuance ($2.7 million). While the proceeds of the equity issuance are intended for the planned acquisition, in the short term those proceeds have created interest income and, to a larger extent, have reduced borrowings and interest expense. Refer to Part I, Item 1 at Note 2 - Pending Acquisition for further discussion of this acquisition.
For the nine months ended June 30, 2026, All Other and Corporate operations reported a net loss of $16.7 million, an increase of $12.6 million when compared with a net loss of $4.1 million for the nine months ended June 30, 2025. The increase was primarily attributable to external integration costs associated with the Company's planned acquisition of CenterPoint Ohio ($12.6 million), as mentioned above, higher operating expenses ($4.5 million) primarily attributable to an increase in internal labor costs, employee benefits and legal and consulting fees, interest expense, net of interest benefits, associated with the June 2026 debt issuances completed to finance the planned acquisition of CenterPoint Ohio ($0.9 million), as mentioned above, and higher income tax expense primarily due to the absence of a federal provision-to-return adjustment benefit recognized in the prior-year period ($0.7 million), as mentioned above. Partially offsetting these increases to net loss was a net interest benefit from the December 2025 equity issuance ($5.8 million), as mentioned above.
Table of Content
Other Income (Deductions)
Net other income on the Consolidated Statements of Income was $11.9 million for the quarter ended June 30, 2026, compared to net other income of $8.5 million for the quarter ended June 30, 2025, for an increase of $3.4 million. This increase can be attributed primarily to interest income associated with proceeds received from the June 2026 debt issuances completed to finance the planned acquisition of CenterPoint Ohio ($2.5 million), an increase in AFUDC driven by changes in the AFUDC capitalization rate ($1.0 million) and an increase in interest income on deferred gas costs ($0.4 million). Partially offsetting these increases was a decrease in non-service pension and post-retirement benefit income ($0.6 million).
Net other income on the Consolidated Statements of Income was $37.1 million for the nine months ended June 30, 2026, compared to net other income of $31.5 million for the nine months ended June 30, 2025, for an increase of $5.6 million. This increase can be attributed primarily to interest income associated with proceeds received from the June 2026 debt issuances completed to finance the planned acquisition of CenterPoint Ohio ($2.5 million), as mentioned above, higher income from unconsolidated subsidiaries ($1.5 million), an increase in AFUDC ($1.5 million), as mentioned above, and a net interest benefit arising from the December 2025 equity issuance ($0.9 million). While the proceeds of the equity issuance are intended for the planned acquisition, in the short term those proceeds have created some interest income and, to a larger extent, have reduced borrowings and interest expense. Refer to Part I, Item 1 at Note 2 - Pending Acquisition for further discussion of this acquisition. The nonrecurrence of a $0.7 million revaluation adjustment for contingent consideration that reduced other income during the nine months ended June 30, 2025 also contributed to the increase in net other income. Partially offsetting these increases was a decrease in non-service pension and post-retirement benefit income ($2.1 million).
Interest Expense on Long-Term Debt
Interest expense on long-term debt on the Consolidated Statement of Income decreased $1.2 million for the quarter ended June 30, 2026 as compared to the quarter ended June 30, 2025. For the nine months ended June 30, 2026, interest expense on long-term debt decreased $10.6 million as compared with the nine months ended June 30, 2025. The decrease in interest expense for both the quarter and nine months ended June 30, 2026 was due to lower average debt balances and weighted average interest rate on long-term debt. The Company repaid a $300 million delayed draw term loan in January 2026. On June 10, 2026, the Company issued $500 million of 4.75% notes, $500 million of 5.05% notes and $500 million of 5.50% notes. On June 11, 2026, the Company redeemed $300 million of 5.50% notes and paid early redemption premiums totaling $0.4 million that were recorded as interest expense on long-term debt in the Integrated Upstream and Gathering segment. On February 19, 2025, the Company issued $500 million of 5.50% notes and $500 million of 5.95% notes. On March 6, 2025, the Company redeemed $450 million of 5.20% notes and $500 million of 5.50% notes and paid early redemption premiums totaling $2.4 million that were recorded as interest expense on long-term debt in the Integrated Upstream and Gathering segment. The Company also redeemed $50 million of 7.395% notes on June 13, 2025.
Other Interest Expense
Other interest expense on the Consolidated Statement of Income decreased $0.7 million for the quarter ended June 30, 2026 as compared to the quarter ended June 30, 2025. This decrease was primarily due to lower average short term debt balances. For the nine months ended June 30, 2026, other interest expense increased $3.3 million as compared to the nine months ended June 30, 2025. This increase was primarily due to financing costs incurred associated with the Company's acquisition of CenterPoint Ohio's natural gas utility.
CAPITAL RESOURCES AND LIQUIDITY
The Company's primary source of cash during the nine-month period ended June 30, 2026 consisted of cash provided by operating activities and net proceeds from the issuances of both common stock and long-term borrowings. The Company's primary source of cash during the nine-month period ended June 30, 2025 consisted of cash provided by operating activities and net proceeds from long-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 2026, the Company expects to use cash provided by operating activities to fund the Company's capital expenditures. In June 2026, the Company issued $1.5 billion of long-term debt, a portion of which was used to redeem $300 million of notes scheduled to mature in October 2026. Looking forward to 2027, based on current forward commodity prices, cash provided by operating activities is expected to exceed capital expenditures. These cash flow projections do not include the impact of the CenterPoint Ohio acquisition or the impact of other acquisitions or divestitures that may arise in the future.
Table of Content
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 Integrated Upstream and Gathering 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 $1,034.5 million for the nine months ended June 30, 2026, an increase of $172.2 million compared with $862.3 million provided by operating activities for the nine months ended June 30, 2025. The increase in cash provided by operating activities primarily reflects higher cash provided by operating activities in the Integrated Upstream and Gathering segment. The increase in the Integrated Upstream and Gathering segment is primarily due to higher natural gas prices in the Appalachian region combined with the timing of cash receipts and hedge settlements.
Investing Cash Flow
Expenditures for Long-Lived Assets
The Company's expenditures for long-lived assets totaled $744.5 million during the nine months ended June 30, 2026 and $596.0 million during the nine months ended June 30, 2025. The table below presents these expenditures:
| Total Expenditures for Long-Lived Assets | |||||||||||||||||
| Nine Months Ended June 30, | 2026 | 2025 | Increase (Decrease) | ||||||||||||||
| (Millions) | |||||||||||||||||
| Integrated Upstream and Gathering: | |||||||||||||||||
| Capital Expenditures | $ | 453.9 | (1) | $ | 412.6 | (2) | $ | 41.3 | |||||||||
| Pipeline and Storage: | |||||||||||||||||
| Capital Expenditures | 166.2 | (1) | 58.1 | (2) | 108.1 | ||||||||||||
| Utility: | |||||||||||||||||
| Capital Expenditures | 120.5 | (1) | 128.3 | (2) | (7.8) | ||||||||||||
| All Other: | |||||||||||||||||
| Capital Expenditures | 4.4 | 0.5 | 3.9 | ||||||||||||||
| Eliminations | (0.5) | (3.5) | 3.0 | ||||||||||||||
| $ | 744.5 | $ | 596.0 | $ | 148.5 | ||||||||||||
Table of Content
(1)At June 30, 2026, capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment, Utility segment and Corporate category included $65.7 million, $29.0 million, $7.2 million and $3.4 million, respectively, of non-cash capital expenditures. At September 30, 2025, capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment and the Utility segment included $87.9 million, $19.4 million and $18.0 million, respectively, of non-cash capital expenditures.
(2)At June 30, 2025, capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment and the Utility segment included $73.1 million, $5.7 million and $9.8 million, respectively, of non-cash capital expenditures. At September 30, 2024, capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment and the Utility segment included $85.0 million, $14.4 million and $20.6 million, respectively, of non-cash capital expenditures.
Integrated Upstream and Gathering
The Integrated Upstream and Gathering segment capital expenditures for the nine months ended June 30, 2026 were primarily upstream well drilling and completion expenditures in the Appalachian region, including $310.3 million spent in the Utica Shale area and $58.2 million spent in the Marcellus Shale area. These amounts included approximately $288.6 million spent to develop proved undeveloped reserves. Integrated Upstream and Gathering segment capital expenditures also included expenditures related to the continued expansion of Midstream Company's Trout Run and Tioga 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.
The Integrated Upstream and Gathering segment capital expenditures for the nine months ended June 30, 2025 were primarily upstream well drilling and completion expenditures in the Appalachian region, including $239.2 million spent in the Utica Shale area and $104.3 million spent in the Marcellus Shale area. These amounts included approximately $182.6 million spent to develop proved undeveloped reserves. Integrated Upstream and Gathering segment capital expenditures also included expenditures related to the continued expansion of Midstream Company's Tioga and Trout Run gathering systems. 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.
Pipeline and Storage
The Pipeline and Storage segment capital expenditures for the nine months ended June 30, 2026 and June 30, 2025 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, the Pipeline and Storage segment capital expenditures for the nine months ended June 30, 2026 included expenditures related to Supply Corporation's Tioga Pathway Project ($46.3 million) and Shippingport Lateral Project ($27.1 million), both of which are discussed below.
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, on-system markets, and markets beyond the Supply Corporation and Empire pipeline systems, including projects to support regional demand for power generation to support the electric grid and data center development and storage enhancements. Expansion and modernization projects 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, are discussed below.
Supply Corporation 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(b)/7(c) application with the FERC on August 21, 2024. FERC issued the Section 7(b)/7(c) certificate on May 5, 2025 and on January 8, 2026, FERC issued the Notice to Proceed with Construction. Construction on the Tioga Pathway Project commenced in February 2026. This project has a projected in-service date of late calendar year 2026 and an estimated capital cost of approximately $101 million. As of June 30, 2026, approximately $51.4 million has been capitalized as Construction Work in Progress for this project.
Table of Content
Additionally, Supply Corporation concluded an open season on February 26, 2025, and based on interest in that open season, designed a project that would allow for the transportation of 205,000 Dth per day of natural gas supplies from its existing Line N pipeline system to a new interconnection with the Shippingport Power Station, a natural gas power generation facility under development in Beaver County, Pennsylvania, which will support a co-located data center that is currently under development (the "Shippingport Lateral Project"). In order to provide this new natural gas transportation capacity, Supply Corporation will construct an approximately 7.5 mile pipeline lateral from its existing Line N pipeline system to a direct interconnection with the facility with the incremental capacity expected to come online in late calendar 2026 and an estimated capital cost of approximately $57 million. Supply Corporation has executed a Precedent Agreement with a developer for 100% of the capacity for the Shippingport Lateral Project and filed an application with FERC under the Commission's prior notice regulations on August 29, 2025. The project obtained FERC authorization on November 7, 2025 and construction commenced in March 2026. As of June 30, 2026, approximately $27.3 million has been capitalized as Construction Work in Progress for this project.
Supply Corporation has also developed its Line N System Upgrade Project, which will consist of modernization of primarily 1960's era pipeline in Beaver County, Pennsylvania, as well as minor compressor station and facility upgrades, to create approximately 294,000 Dth per day of additional natural gas transportation capacity (1) from a new interconnection on the southern portion of Supply Corporation's Line N system in Greene County, Pennsylvania to an existing Supply Corporation interconnection with Tennessee Gas Pipeline Company, LLC at Mercer and (2) from an existing Supply Corporation interconnection with Texas Eastern Transmission, LP at Holbrook to a new interconnection at the Shippingport Industrial Park in Shippingport, Pennsylvania. Supply Corporation executed long-term precedent agreements with two shippers for 100% of the incremental capacity created by the project. The project has a projected in-service date of late calendar 2028 and an estimated capital cost of approximately $100 million. As of June 30, 2026, $0.4 million has been spent to study this project, all of which has been included in Deferred Charges on the Consolidated Balance Sheet at June 30, 2026.
Utility
The majority of the Utility segment capital expenditures for the nine months ended June 30, 2026 and June 30, 2025 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 nine months ended June 30, 2026 and fiscal 2025, the Company has financed capital expenditures with cash from operations, net proceeds from the issuance of common stock and long-term debt. Going forward, the Company expects to use cash from operations and short-term borrowings, as needed, to finance capital expenditures. The level of short-term borrowings will depend upon the amount of cash provided by operations, which, in turn, will likely be most impacted by natural gas production and the associated commodity price realizations in the Integrated Upstream and Gathering segment. It will also likely depend on the timing of gas cost and base rate recovery in the Utility segment as well as the timing of base rate recovery in the Pipeline and Storage 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 and Pipeline and Storage segments 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 decreased $150.2 million when comparing the balance sheet at June 30, 2026 to the balance sheet at September 30, 2025. The maximum amount of short-term debt outstanding during the nine months ended June 30, 2026 was $311.0 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
Table of Content
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. As of June 30, 2026, the Company did not have any short-term notes payable to banks or commercial paper outstanding.
On October 20, 2025, the Company entered into a Securities Purchase Agreement (the "Purchase Agreement") with CenterPoint Energy Resources Corp. (the "Seller"), pursuant to which, among other things, the Company agreed to acquire from the Seller all of the issued and outstanding equity interests of Vectren Energy Delivery of Ohio, LLC (the "Acquired Company" or "CenterPoint Ohio"), the Seller's Ohio natural gas local distribution company, for an aggregate purchase price of $2.62 billion, subject to customary adjustments (the "Purchase Price"), as provided in the Purchase Agreement (the "Transaction"). The Purchase Price will be paid through a combination of cash and a promissory note to be issued by the Company to the Seller at closing pursuant to a Seller Note Agreement (the "Seller Note Agreement") between the Company, as borrower, and the Seller, as lender. The Seller Note Agreement, which was part of the Seller's desired transaction structure and was incorporated into the Company's business valuation, will provide a $1.2 billion unsecured term loan credit facility (the "Seller Note Facility") that matures on the last business day that is not more than 364 days from the closing of the Transaction.
The borrowings under the Seller Note Facility will bear interest at a rate of 6.5% per annum. The Seller Note Agreement will contain customary representations and affirmative, negative and financial covenants, consistent with the Company's February 2024 term loan agreement discussed below. The Seller Note Agreement will also include covenants restricting certain actions with respect to the Acquired Company. The Seller Note Agreement will contain certain specified events of default, and should an event of default occur, the lender is entitled to exercise certain remedies, including acceleration of the loan and related obligations.
The Seller Note Agreement will contain a covenant defeasance provision that permits the Company to relieve itself from its obligations to comply with covenants under the Seller Note Agreement upon deposit of an amount with a paying agent sufficient to pay the principal of and interest due on the loan on each applicable interest payment date and the maturity date.
In connection with its entry into the Purchase Agreement, the Company entered into a bridge facility commitment letter (the "Bridge Commitment Letter"), pursuant to which The Toronto-Dominion Bank, New York Branch ("TD Bank") and Wells Fargo Bank, National Association ("Wells Fargo Bank" and, together with TD Bank, the "Commitment Parties"), agreed to provide to the Company loans under a senior unsecured bridge loan facility (the "Bridge Facility") composed of a $1.42 billion 364-day tranche (the "Acquisition Tranche"), the proceeds of which will be used, if needed, to finance the Transaction, and a $1.2 billion 364-day tranche (the "Seller Note Tranche"), the proceeds of which will be used, if needed, to refinance the Seller Note Facility at its scheduled maturity.
On November 6, 2025, the Company entered into a 364-day term loan facility commitment letter (the "Term Loan Commitment Letter"), pursuant to which the Commitment Parties and ten additional banks, all of which are lenders under our primary credit facility, agreed to provide to the Company loans under a 364-day senior unsecured term loan facility (the "Term Loan Facility") in the amount of $1.42 billion, the proceeds of which will be used, if needed, to finance the Transaction. Entering into the Term Loan Commitment Letter enabled the Company to terminate the commitments under the Bridge Commitment Letter in respect of the Acquisition Tranche. Also on November 6, 2025, the same ten additional banks joined the Commitment Parties as parties to the Bridge Commitment Letter in respect of the Seller Note Tranche.
On December 17, 2025, the Company completed the issuance and sale, in a private placement, of 4,402,513 shares of the Company's common stock, par value $1.00 per share, at a price of $79.50 per share. After deducting placement fees, the net proceeds to the Company amounted to $338.4 million.
On June 10, 2026, the Company issued $500.0 million of 4.75% notes due May 15, 2029, $500.0 million of 5.05% notes due October 15, 2031 and $500.0 million of 5.50% notes due May 15, 2036. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $495.6 million, $494.2 million and $491.4 million, respectively. 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 6.75% on the 4.75% notes, 7.05% on the 5.05% notes and 7.50% on the 5.50% notes, 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. If the CenterPoint Ohio acquisition is not consummated for any reason, the Company will be required to redeem the notes in a special mandatory
Table of Content
redemption at a price equal to 101% of the principal amount of the notes. A portion of the net proceeds of these debt issuances was used for general corporate purposes, including the June 11, 2026 redemption of $300.0 million of the Company's 5.50% notes that were scheduled to mature in October 2026. The Company redeemed those notes for $301.2 million, plus accrued interest. The Company invested the remaining net proceeds from these debt issuances in temporary cash investments and expects to use that cash in addition to commercial paper or other short-term borrowing facilities to fund the purchase price of the CenterPoint Ohio acquisition at closing, including the payment of related fees and expenses.
The net proceeds of the common stock issuance and long-term debt issuances discussed above reduced the commitments under the Term Loan Facility to zero, thus terminating the Term Loan Commitment Letter. The net proceeds of the long-term debt issuances also reduced the commitments under the Seller Note Tranche of the Bridge Commitment Letter to approximately $1.10 billion. The Company expects to further reduce the commitments under the Bridge Facility, possibly to zero, through additional financings prior to the scheduled maturity of the Seller Note Facility, but there can be no assurance such financings will occur and any such expectation is subject to market conditions.
The Company is subject to certain customary fees with respect to the Bridge Facility. Interest on borrowings under the Bridge Facility would accrue at one of two rates, at the option of the Company: Term SOFR plus an applicable margin of 1.125% to 1.750%, or a base rate (at least as great as one-month Term SOFR plus 1.0%) plus an applicable margin of 0.125% to 0.750%. In each case, the applicable margin would depend on the Company's credit ratings (at current ratings, the applicable margin would be 1.500% for Term SOFR loans and 0.500% for base rate loans). The applicable margin would increase by an additional 0.25% on each of the 90th, 180th and 270th day after the funding date for any loans outstanding under the Bridge Facility. Any borrowings under the Bridge Facility would mature 364 days from the funding date, which would be on or around the scheduled maturity of the Seller Note Facility.
The availability of borrowings under the Bridge Facility is subject to the satisfaction of certain customary conditions for transactions of these types. Any definitive financing documentation for the Bridge Facility will contain customary representations and warranties, covenants and events of defaults for transactions of these types. The Company expects to execute permanent financing prior to the funding date of the Bridge Facility, such that borrowings under this facility would not be incurred. There can be no assurance, however, such permanent financing will occur and any such expectation is subject to market conditions.
On March 27, 2026, the Company entered into an Amended and Restated Credit Agreement (the "Credit Agreement") with PNC Bank, National Association, as administrative agent and lender, and 12 additional lenders. The Credit Agreement amended and restated that certain credit agreement, dated as of February 28, 2022, among the Company, JPMorgan Chase Bank, N. A., as administrative agent, and the lenders party thereto. The Credit Agreement provides a $1.3 billion unsecured committed revolving credit facility, an increase of $300 million from the prior agreement. The facility has an initial maturity date of March 27, 2031. The Company may use the proceeds of loans under the Credit Agreement (a) to repay its (i) obligations under its commercial paper program, (ii) other short term credit facilities and (iii) maturing long-term debt obligations, (b) for general corporate purposes of the Company and its subsidiaries in the ordinary course of business, including for working capital, capital expenditure and other lawful corporate purposes and (c) to fund certain permitted acquisitions, including the CenterPoint Ohio acquisition, and other investments.
The total amount available to be issued under the Company's commercial paper program is $500 million. The commercial paper program is backed by the Credit Agreement. The Company also has two 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. 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 of the 12 banks that were then lenders under the Company's prior primary revolving credit agreement. The Term Loan Agreement provided a $300.0 million unsecured committed delayed draw term loan facility with a maturity date of February 14, 2026, and the Company had the ability to select interest periods of one, three or six months for borrowings. Borrowings under the Term Loan Agreement bore interest at a rate equal to SOFR for the applicable interest period, plus an adjustment of 0.10%, plus a spread of 1.375%. On January 22, 2026, the Company repaid all outstanding obligations under the Term Loan Agreement, and the agreement was terminated.
The Credit Agreement 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
Table of Content
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. Since that date, the Company recorded non-cash, after-tax ceiling test impairments totaling $797.0 million. As a result, at June 30, 2026, $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. 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. Finally, for purposes of calculating the debt to capitalization ratio, the Company's $1.2 billion obligation under the Seller Note Facility, which is to be incurred at the closing of the Transaction, will be excluded from the definition of consolidated indebtedness upon such time and to the extent that the Company, in accordance with the Seller Note Agreement, deposits with a paying agent funds for defeasance of the Seller Note Facility.
At June 30, 2026, the Company's debt to capitalization ratio, as calculated under the Credit Agreement, was 0.46. The constraints specified in the Credit Agreement would have permitted an additional $4.29 billion in short-term and/or long-term debt to be outstanding at June 30, 2026 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 $125.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $125.0 million or more to cause, such indebtedness to become due prior to its stated maturity.
On February 19, 2025, the Company issued $500.0 million of 5.50% notes due March 15, 2030 and $500.0 million of 5.95% notes due March 15, 2035. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $495.2 million and $493.5 million, respectively. 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% on the 5.50% notes and 7.95% on the 5.95% notes, 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 these debt issuances were used for general corporate purposes, including the March 6, 2025 redemptions of $450.0 million of the Company's 5.20% notes that were scheduled to mature in July 2025 and $500.0 million of the Company's 5.50% notes that were scheduled to mature in January 2026. The Company redeemed those notes for $450.8 million and $503.3 million, respectively, plus accrued interest. The remaining proceeds of the debt issuances were used to repay a portion of short-term borrowings the Company incurred to fund a trust for the benefit of holders of the 7.38% notes outstanding under the Company's 1974 indenture.
None of the Company's long-term debt at June 30, 2026 had a maturity date within the following twelve-month period. The Current Portion of Long-Term Debt at September 30, 2025 consisted of a $300.0 million long-term delayed draw term loan with a maturity date in February 2026 that was repaid in January 2026. The Company's present liquidity position is believed to be adequate to satisfy known demands.
The Company's embedded cost of long-term debt was 4.89% at June 30, 2026 and 4.92% at June 30, 2025.
Table of Content
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 nine months ended June 30, 2026, and does not anticipate making any such contributions during the remainder of fiscal 2026. The Company also did not make any contributions to its VEBA trusts for its other post-retirement benefits during the nine months ended June 30, 2026, and does not anticipate making any such contributions during the remainder of fiscal 2026.
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 June 30, 2026, 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 2025 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 authorized 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. These revenue requirement increases are being reflected in customer bills on a levelized basis over the three-year rate plan. The revenue requirement for each year of the three-year plan has been reduced by $14 million for actuarial projections of income that is
Table of Content
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.
On May 5, 2026, Distribution Corporation filed a petition with the NYPSC for, among other things, authorization to implement a system modernization tracker reconciliation mechanism through which qualified leak prone pipe removal costs incurred by the Company would be tracked and recovered. The petition remains pending with the Commission.
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.
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 with a cap equivalent to 5% of distribution revenues, and on January 1, 2025, the Company initiated recovery of eligible costs on incremental rate base added after September 30, 2024. Effective April 1, 2026, the DSIC cap was met and the DSIC will be reset to zero when new base rates become effective as a result of the Company's recent rate filing.
On January 28, 2026, Distribution Corporation made a filing with the PaPUC seeking an increase in its annual base rate operating revenues of $19.7 million with a proposed effective date of March 29, 2026. The Company is proposing, among other things, a new residential energy efficiency pilot program and to make permanent its weather normalization adjustment mechanism. The Company is also proposing reactivation of the OPEB surcredit (Rider I) to refund $7.2 million for customer bill relief. As reflected in a February 19, 2026 PaPUC Order, the filing was suspended until October 29, 2026 by operation of law unless directed otherwise by the PaPUC. Final briefs were submitted in the case on July 1, 2026. A decision is generally anticipated from the administrative law judge in August 2026.
Pipeline and Storage
Supply Corporation filed an NGA Section 4 rate case at FERC on April 30, 2026 proposing rate increases to be effective November 1, 2026. Supply Corporation's filing requests an annual cost of service of approximately $404 million, an increase of approximately $95 million from Supply Corporation's settlement of its 2023 rate proceeding. The proposal also includes, among other things, a modernization cost recovery mechanism. By regulation, the proposed rates will become effective November 1, 2026 subject to refund, unless the parties in the case reach a settlement.
On March 17, 2025, FERC approved an amendment to Empire's 2019 rate case settlement, which provides for a modest reduction in Empire's transportation unit rates, effective November 1, 2025. This settlement amendment is estimated to decrease Empire's revenues on a yearly basis by approximately $0.5 million. Empire will not be able to file a new Section 4 rate case before April 30, 2027 and is required to file a Section 4 rate case by May 31, 2031.
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. In 2021, the Company set methane intensity reduction targets at each of its businesses. 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 8 - Commitments and Contingencies under the heading "Environmental Matters."
Table of Content
While the current federal administration has initiated efforts to roll-back and/or limit certain environmental initiatives, legislative and regulatory measures concerning 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, 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.
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. In New York, the CLCPA, which was passed in 2019, mandates reducing statewide 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. Statements from New York's Governor and the state's 2025 New York State Energy Plan acknowledge that the near term targets of the statute may not be achievable in the required timeframes. In May 2026, the Governor signed a law amending the CLCPA to, among other things, modify the statewide 40% by 2030 mandate to require the NYDEC to promulgate regulations designed to achieve a 60% by 2040 target. 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, and in December 2025 the Governor approved legislation that will require residential natural gas service applicants to pay the installation costs for the first 100 feet of facilities necessary to provide natural gas service commencing December 19, 2026. The May 2023 legislation is subject to ongoing litigation, with the parties agreeing, in November 2025, to suspend the requirements of the legislation pending resolution of appellate proceedings. In addition, the NYDEC, in conjunction with the New York State Energy Research and Development Authority, has engaged in certain efforts to develop a cap-and-invest program in the state, although issuance of certain key regulations necessary to implement the program has been delayed. The May 2026 amendments referenced above have extended the date for regulatory action to December 31, 2028. The above-enumerated initiatives could impact the Company's customer base and assets, and 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 federal and state administrative agencies, make it difficult to predict a long-term business impact across twenty or more years. Federal, state or local governments may also 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.
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
Table of Content
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.Changes in economic conditions, including the imposition of additional tariffs on U.S. imports and related retaliatory tariffs, 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;
4.The Company's ability to complete strategic transactions, such as the planned CenterPoint Ohio acquisition, including receipt of required regulatory clearances and satisfaction of other conditions to closing, and to recognize the anticipated benefits of such transactions;
5.Governmental/regulatory actions and/or market pressures to reduce or eliminate reliance on natural gas;
6.The Company's ability to estimate accurately the time and resources necessary to meet emissions targets;
7.Changes in the price of natural gas;
8.Impairments under the SEC's full cost ceiling test for natural gas reserves;
9.The creditworthiness or performance of the Company's key suppliers, customers and counterparties;
10.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, other investments, and acquisitions, including any downgrades in the Company's credit ratings and changes in interest rates and other capital market conditions;
11.Negotiations with the collective bargaining units representing the Company's workforce, including potential work stoppages during negotiations;
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, including the impact of issues that may arise from the use of artificial intelligence technologies;
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, 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;
15.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;
16.Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits;
Table of Content
17.Other changes in price differentials between similar quantities of natural gas having different quality, heating value, hydrocarbon mix or delivery date;
18.The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company;
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.
National Fuel Gas Co. published this content on July 30, 2026, and is solely responsible for the information contained herein. Distributed via EDGAR on July 30, 2026 at 15:55 UTC. If you believe the information included in the content is inaccurate or outdated and requires editing or removal, please contact us at [email protected]