What changed in this filing

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Item 2. Management’s Discussion and Analysis

2026-04-30 compared with 2026-01-29 · 289 added, 158 removed, 356 unchanged (56% of the section changed)

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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.

The Company reports

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financial results for three business segments.

For a discussion of the Company's earnings, refer to the Results of Operations section below.

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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 is expected to commence in February 2026.

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 natural gas supplies to the Shippingport Power Station, a natural gas power generation facility under development in Beaver County, Pennsylvania.

The project obtained FERC authorization under the Commission’s prior notice regulations on November 7, 2025.

The Tioga Pathway Project and the Shippingport Lateral Project are both discussed in more detail in the Capital Resources and Liquidity section that follows.

The project obtained FERC authorization under the Commission’s prior notice regulations on November 7, 2025 and construction commenced in March 2026.

In April 2026, Supply Corporation executed a long-term precedent agreement with a shipper 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,

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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.

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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.

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.

In addition, on March 17, 2025, FERC approved an amendment to Empire's 2019 rate case settlement.

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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 in the fourth quarter of calendar 2026, pending completion of a notice filing and review with the PUCO, Hart-Scott-Rodino review, and other customary closing conditions.

Closing is expected to occur in the fourth quarter of calendar 2026, pending completion of a review with the PUCO and other customary closing conditions.

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, will 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.

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

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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.

In connection with its entry into the Purchase Agreement, the Company entered into a senior unsecured bridge loan facility commitment letter supported by the Commitment Parties, as well as a 364-day term loan facility commitment letter 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 fully supports any portion of the purchase price that has not been permanently financed.

In connection with the Purchase Agreement, the Company is a party to 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.

Together, the commitment letters fully support any portion of the aggregate purchase price that has not been permanently financed.

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 December 31, 2025, 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 December 31, 2025.

At March 31, 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 March 31, 2026.

Please refer to the Critical Accounting Estimates section below for more details on this matter and a sensitivity analysis concerning commodity price changes.

The Company expects to use cash from operations, equity proceeds, and short-term and/or long-term borrowings, as needed, to meet its financing needs for the remainder of fiscal 2026, including the repayment of a $300.0 million delayed draw term loan scheduled to mature in February 2026 that was repaid in January 2026 and any potential funding for the CenterPoint Ohio acquisition.

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, equity proceeds, and short-term and/or long-term borrowings, as needed, to meet its financing needs for the remainder of fiscal 2026, including any potential funding for the CenterPoint Ohio acquisition and the repayment of its $300.0 million of 5.50% notes with a maturity date in October 2026.

The Company continues to evaluate these financing needs and options to meet them.

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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

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cost methodology, the Company is required to perform a quarterly ceiling test.

In accordance with the full cost methodology, the Company is required to perform a quarterly ceiling test.

Under the ceiling test, the present value of future revenues from the Company's exploration and production reserves based on an unweighted arithmetic average of first day of the month commodity prices for each month within the twelve-month period prior to the end of the reporting period (the “ceiling”) is compared with the book value of the Company’s exploration and production properties at the balance sheet date.

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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 December 31, 2025, the ceiling exceeded the book value of the exploration and production properties by approximately $1.3 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 December 31, 2025, based on the quoted Henry Hub spot price for natural gas, was $3.39 per MMBtu.

Because actual pricing of the Company’s producing properties vary depending on their location and hedging, the prices used to calculate the ceiling may differ from the Henry Hub price, which is only indicative of 12-month average prices for the twelve months ended December 31, 2025.

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 December 31, 2025 in the ceiling test calculation, the ceiling would have exceeded the book value of the Company's exploration and production properties by approximately $953.5 million (after-tax), which would not have resulted in an impairment charge.

At March 31, 2026, the ceiling exceeded the book value of the exploration and production properties by approximately $1.6 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 March 31, 2026, based on the quoted Henry Hub spot price for natural gas, was $3.72 per MMBtu.

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 March 31, 2026 in the ceiling test calculation, the ceiling would have exceeded the book value of the Company's exploration and production properties by approximately $1.2 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.

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It is difficult to predict what factors could lead to future non-cash impairments under the SEC's full cost ceiling test.

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RESULTS OF OPERATIONS

The Company's earnings were $181.6 million for the quarter ended December 31, 2025 compared to earnings of $45.0 million for the quarter ended December 31, 2024.

The increase in earnings of $136.6 million is primarily the result of current year earnings recognized in the Integrated Upstream and Gathering segment compared to a prior year loss combined with higher earnings in the Utility segment.

A higher loss in the Corporate category and lower earnings in the Pipeline and Storage segment partially offset these increases.

The Company's earnings for the quarter ended December 31, 2024 included non-cash impairment charges of $141.8 million ($103.6 million after-tax) in the Integrated Upstream and Gathering segment, consisting mostly of ceiling test impairment charges of $108.3 million ($79.1 million after-tax).

The Company's earnings were $247.7 million for the quarter ended March 31, 2026 compared to earnings of $216.4 million for the quarter ended March 31, 2025.

The increase in earnings of $31.3 million is primarily the result of higher earnings in the Integrated Upstream and Gathering segment.

The Company's earnings were $429.3 million for the six months ended March 31, 2026 compared to earnings of $261.3 million for the six months ended March 31, 2025.

The increase in earnings of $168.0 million is primarily the result of higher earnings in the Integrated Upstream and Gathering segment.

The Company's earnings for the six months ended March 31, 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.

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Three Months Ended

March 31, Six Months Ended

(Thousands) 2026 2025 Increase

(Decrease) 2026 2025 Increase

Integrated Upstream and Gathering $ 152,030 $ 124,170 $ 27,860 $ 276,077 $ 104,538 $ 171,539

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Total Consolidated $ 247,668 $ 216,358 $ 31,310 $ 429,313 $ 261,344 $ 167,969

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Integrated Upstream and Gathering

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Three Months Ended

March 31, Six Months Ended

(Thousands) 2026 2025 Increase

(Decrease) 2026 2025 Increase

Gas Produced in Appalachia (after Hedging) $ 351,523 $ 310,570 $ 40,953 $ 667,378 $ 557,757 $ 109,621

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$ 358,823 $ 315,191 $ 43,632 $ 682,045 $ 567,499 $ 114,546

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Production Volumes

Three Months Ended

March 31, Six Months Ended

2026 2025 Increase

(Decrease) 2026 2025 Increase

Gas Production (MMcf) 102,004 105,514 (3,510) 211,185 203,232 7,953

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Three Months Ended

March 31, Six Months Ended

2026 2025 Increase

(Decrease) 2026 2025 Increase

Average Gas Price/Mcf

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2026 Compared with 2025

Operating revenues for the Integrated Upstream and Gathering segment increased $70.9 million for the quarter ended December 31, 2025 as compared with the quarter ended December 31, 2024.

Gas production revenue after hedging increased $68.7 million due to the impact of a $0.36 per Mcf increase in the weighted average price of natural gas after hedging, combined with a 11.5 Bcf increase in natural gas production.

The increase in natural gas production was largely due to pads recently turned in line.

Operating revenues for the Integrated Upstream and Gathering segment increased $43.6 million for the quarter ended March 31, 2026 as compared with the quarter ended March 31, 2025.

Gas production revenue after hedging increased $41.0 million due to the impact of a $0.51 per Mcf increase in the weighted average price of natural gas after hedging, partially offset by a 3.5 Bcf decrease in natural gas production.

The decrease in natural gas production was largely due to weather-driven completion delays and natural gas production declines on producing wells.

In addition, other revenue increased $3.3 million primarily due to changes in segment reporting.

The change in segment reporting is fully offset in other operating expenses.

Slightly offsetting these increases, Gathering revenue decreased $0.7 million as a result of natural production declines by producers connected to the Trout Run gathering system.

The Integrated Upstream and Gathering segment's earnings for the quarter ended December 31, 2025 were $124.0 million, an increase of $143.6 million when compared with a loss of $19.6 million for the quarter ended December 31, 2024.

Slightly offsetting these increases, gathering revenue decreased $0.6 million as a result of natural production declines by producers connected to the Tioga and Trout Run gathering systems.

Operating revenues for the Integrated Upstream and Gathering segment increased $114.5 million for the six months ended March 31, 2026 as compared with the six months ended March 31, 2025.

Gas production revenue after hedging increased $109.6 million due to the impact of a $0.42 per Mcf increase in the weighted average price of natural gas after hedging, coupled with an 8.0 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 natural gas production declines on producing wells.

In addition, other revenue increased $6.2 million primarily due to changes in segment reporting.

The change in segment reporting is fully offset in other operating expenses.

Slightly offsetting these increases, gathering revenue decreased $1.3 million as a result of natural production declines by producers connected to the Tioga and Trout Run gathering systems.

The Integrated Upstream and Gathering segment's earnings for the quarter ended March 31, 2026 were $152.0 million, an increase of $27.8 million when compared with earnings of $124.2 million for the quarter ended March 31, 2025.

The $27.8 million increase can be attributed to the following factors:

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Lower non-cash impairments of assets $ 103.6 (1)

Higher natural gas prices after hedging $ 40.5

Lower interest expense 4.2 (1)

Higher other revenue 2.6

Premiums paid on early redemption of debt 1.7 (2)

Lower natural gas production (8.2)

Higher depletion expense (4.0) (3)

Higher lease operating expenses (3.8) (4)

Higher other operating expenses (3.2) (5)

Higher income tax expense (2.0) (6)

(1) The decrease in interest expense is mainly attributed to lower short-term and long-term intercompany borrowings.

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(2) Represents the segment's share of the premiums paid by the Company to redeem long-term debt during the quarter ended March 31, 2025.

(3) The increase in depletion is mainly attributed to a higher depletion rate.

(4) The increase in lease operating expenses was primarily the result of additional third-party gathering and transportation costs combined with higher road maintenance costs.

(5) The increase in other operating expenses is mainly attributed to a change in segment reporting combined with higher gathering operation and maintenance expense and higher abandonment accretion expense.

These were partially offset by higher abandonment costs recognized during the quarter ended March 31, 2025.

(6) The increase in income tax expense was primarily driven by an increase in state tax expense due to higher pre-tax income.

The Integrated Upstream and Gathering segment's earnings for the six months ended March 31, 2026 were $276.1 million, an increase of $171.6 million when compared with earnings of $104.5 million for the six months ended March 31, 2025.

The $171.6 million increase can be attributed to the following factors:

Prior period's impairment of assets $ 103.6 (1)

Higher natural gas prices after hedging 69.4

Higher natural gas production 17.2

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Higher other revenue 4.9

Premiums paid on early redemption of debt 1.7 (3)

Earnings impact associated with remeasurement of state deferred income taxes due to ceiling test impairments 1.0 (4)

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Higher income tax expense (4.4) (8)

Higher other tax expense (1.3) (8)

Lower gathering revenues (1.0)

Other items (0.8)

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(2) The decrease in interest expense is mainly attributed to lower short-term and long-term intercompany borrowings.

(3) The increase was due to a $1.0 million earnings reduction associated with the remeasurement of state deferred income taxes for the quarter ended December 31, 2024.

(4) The increase in depletion is mainly attributed to higher production.

(5) The increase in lease operating expenses was primarily the result of higher third-party gathering and transportation costs combined with higher workover and repairs and maintenance costs.

(6) The increase in other operating expenses is mainly attributed to a change in segment reporting, as well as higher gathering operation and maintenance, higher personnel costs and higher abandonment accretion expense, partially offset by higher abandonment costs recognized in fiscal 2024.

(7) The increase in income tax expense was primarily driven by an increase in state tax expense due to higher pre-tax income.

(8) The increase in other tax expense was primarily attributable to higher Impact Fees in the Appalachian region as the Company moved into a higher rate tier due to higher NYMEX pricing combined with higher well count.

(3) Represents the segment's share of the premiums paid by the Company to redeem long-term debt during the six months ended March 31, 2025.

(4) The increase was due to a $1.0 million earnings reduction associated with the remeasurement of state deferred income taxes for the six months ended March 31, 2025.

(5) The increase in depletion is mainly attributed to higher production combined with a higher depletion rate.

(6) The increase in lease operating expenses was primarily the result of additional third-party gathering and transportation costs combined with higher road maintenance costs.

(7) The increase in other operating expenses is 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 higher abandonment costs recognized during the six months ended March 31, 2025.

(8) The increase in income tax expense was primarily driven by higher state tax expense due to an increase in pre-tax income.

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Pipeline and Storage

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Three Months Ended

March 31, Six Months Ended

(Thousands) 2026 2025 Increase

(Decrease) 2026 2025 Increase

Firm Transportation $ 82,747 $ 82,224 $ 523 $ 163,632 $ 163,310 $ 322

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Firm Storage Service 25,677 25,288 389 50,814 50,281 533

Interruptible Storage Service — — —

Other 2,738 1,804 934 3,494 2,219 1,275

$ 111,463 $ 109,573 $ 1,890 $ 218,364 $ 216,186 $ 2,178

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Pipeline and Storage Throughput

Three Months Ended

March 31, Six Months Ended

(MMcf) 2026 2025 Increase

(Decrease) 2026 2025 Increase

Firm Transportation 246,946 234,730 12,216 461,019 437,612 23,407

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2026 Compared with 2025

Operating revenues for the Pipeline and Storage segment remained relatively flat for the quarter ended December 31, 2025 as compared with the quarter ended December 31, 2024.

Transportation volume for the quarter ended December 31, 2025 increased by 11.2 Bcf, from the quarter ended December 31, 2024.

The increase in transportation volume for the quarter ended December 31, 2025 is primarily due to increased utilization resulting from colder weather.

Operating revenues for the Pipeline and Storage segment increased $1.9 million for the quarter ended March 31, 2026 as compared with the quarter ended March 31, 2025.

The increase in operating revenue was primarily driven by higher other revenues of $0.9 million, along with an increase in transportation revenues of $0.6 million and an increase in storage revenues of $0.4 million.

The increase in other revenues primarily reflects an adjustment to match electric surcharge revenues with electric power costs recorded in operation and maintenance.

The increase in transportation revenues was primarily attributable to new long-term contracts and rate increases on existing contracts, partially offset by revisions to existing contracts.

The increase in storage revenues was primarily attributable to rate increases and deliverability enhancements on existing contracts.

Operating revenues for the Pipeline and Storage segment increased $2.2 million for the six months ended March 31, 2026 as compared with the six months ended March 31, 2025.

The increase in operating revenue was primarily driven by higher other revenues of $1.3 million, along with an increase in storage revenues of $0.5 million and an increase in transportation revenues of $0.4 million.

The increase in other revenues primarily reflects an adjustment to match electric surcharge revenues with electric power costs recorded in operation and maintenance expense.

The increase in storage revenues was primarily attributable to rate increases and deliverability enhancements on existing contracts coupled with increased commodity revenue driven by colder weather.

The increase in transportation revenues was primarily attributable to new long-term contracts and rate increases on existing contracts, partially offset by revisions to existing contracts.

Transportation volume for the quarter and six months ended March 31, 2026 increased by 12.3 Bcf and 23.5 Bcf, respectively, from the prior year's quarter and six month periods.

The increase in transportation volume for both the quarter and six months ended March 31, 2026 is primarily due to increased utilization resulting from colder weather.

Volume fluctuations, other than those caused by the addition or termination of contracts, generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.

The Pipeline and Storage segment’s earnings for the quarter ended December 31, 2025 were $31.2 million, a decrease of $1.3 million when compared with earnings of $32.5 million for the quarter ended December 31, 2024.

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The Pipeline and Storage segment’s earnings for the quarter ended March 31, 2026 were $31.6 million, a decrease of $0.1 million when compared with earnings of $31.7 million for the quarter ended March 31, 2025.

The $0.1 million decrease can be attributed to the following factors:

Higher operating revenues $ 1.5

Higher depreciation expense (1.1) (1)

Lower other income (0.5) (2)

(1) The increase in depreciation expense primarily reflects additional plant in-service.

(2) 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.

The Pipeline and Storage segment’s earnings for the six months ended March 31, 2026 were $62.8 million, a decrease of $1.4 million when compared with earnings of $64.2 million for the six months ended March 31, 2025.

The $1.4 million decrease can be attributed to the following factors:

Higher operating revenues $ 1.7

Lower other income (1.7) (1)

Higher depreciation expense (1.5) (2)

Other items 0.1

(1) 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.

(2) The increase in depreciation expense primarily reflects additional plant in-service.

Utility Operating Revenues

Three Months Ended

March 31, Six Months Ended

(Thousands) 2026 2025 Increase

(Decrease) 2026 2025 Increase

Retail Sales Revenues:

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$ 425,914 $ 343,693 $ 82,221 $ 685,052 $ 572,201 $ 112,851

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Utility Throughput

Three Months Ended

March 31, Six Months Ended

(MMcf) 2026 2025 Increase

(Decrease) 2026 2025 Increase

Retail Sales:

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64,322 62,919 1,403 109,571 101,455 8,116

Three Months Ended December 31, Percent Colder (Warmer) Than

Three Months Ended March 31, Percent Colder (Warmer) Than

Normal 2026 2025 Normal (1)

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Buffalo, NY 3,226 3,282 3,116 1.7 % 5.3 %

2,126 2,281 1,884 7.3 % 21.1 %

Erie, PA 3,023 3,079 3,017 1.9 % 2.1 %

Six Months Ended March 31,

Buffalo, NY 5,352 5,563 5,000 3.9 % 11.3 %

Erie, PA 4,917 5,200 4,714 5.8 % 10.3 %

(1) Percents compare actual 2026 degree days to normal degree days and actual 2026 degree days to actual 2025 degree days.

(2) Normal degree days changed in January 2025 from NOAA 30-year degree days to NOAA 15-year degree days with the implementation of new base rates in New York.

2026 Compared with 2025

Operating revenues for the Utility segment increased $30.6 million for the quarter ended December 31, 2025 as compared with the quarter ended December 31, 2024.

Operating revenues for the Utility segment increased $82.2 million for the quarter ended March 31, 2026 as compared with the quarter ended March 31, 2025.

This increase resulted from a $77.3 million increase in retail gas sales revenue, a $3.1 million increase in transportation revenue and a $1.9 million increase in other revenue.

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Additional details regarding the base rate regulatory proceeding can be found in the Rate Matters section below.

The increase in retail gas sales revenue also reflects higher revenues collected from customers for purchased gas costs resulting from a 4.0 Bcf increase in throughput mainly due to colder weather.

The increase in retail gas sales revenue also reflects higher revenues collected from customers for purchased gas costs resulting mainly from an increase in the cost of gas sold (per Mcf) as well as a 1.0 Bcf increase in throughput mainly due to colder weather.

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 an increase to revenue from a distribution system improvement charge (“DISC”) 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 increase in transportation revenue also reflects a 0.4 Bcf increase in throughput due primarily to colder weather.

The Utility segment’s earnings for the quarter ended December 31, 2025 were $34.1 million, an increase of $1.6 million when compared with earnings of $32.5 million for the quarter ended December 31, 2024.

The increase in other revenue was primarily due to certain net positive revenue adjustments as a result of operational performance of safety performance measures in accordance with the rate settlement ($0.8 million), as well as increases in late payment charges billed to customers ($0.5 million) and capacity release revenues ($0.4 million).

Operating revenues for the Utility segment increased $112.9 million for the six months ended March 31, 2026 as compared with the six months ended March 31, 2025.

This increase resulted from a $105.9 million increase in retail gas sales revenue, a $4.7 million increase in transportation revenue and a $2.2 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 5.0 Bcf increase in throughput mainly due to colder weather.

Retail gas sales revenue and transportation revenue were also impacted by an increase to revenue from the DISC modernization tracker in Pennsylvania, as discussed above.

The increase in transportation revenue also reflects a 3.1 Bcf

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increase in throughput due primarily to colder weather.

The increase in other revenue was primarily due to certain net positive revenue adjustments as a result of operational performance of safety performance measures in accordance with the rate settlement ($0.8 million), as well as increases in late payment charges billed to customers ($0.8 million) and capacity release revenues ($0.6 million).

The Utility segment’s earnings for the quarter ended March 31, 2026 were $65.3 million, an increase of $1.8 million when compared with earnings of $63.5 million for the quarter ended March 31, 2025.

The increase can be attributed to the following factors:

Impact of new base rates in New York $ 2.9

Impact of higher customer usage 2.8

Impact of regulatory revenue adjustments $ 3.6 (1)

Impact of new base rates in New York 3.1

Higher operating expenses (2.9) (2)

Impact of lower customer usage (1.2)

Higher depreciation expense (1.2) (3)

Other items 0.4

(1) Amount primarily reflects an increase in earnings 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.

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(2) The increase in operating expenses is largely attributable to higher personnel costs and higher uncollectible expenses.

(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 personnel costs and higher uncollectible expenses as a result of higher operating revenue.

(3) The increase in depreciation expense is attributable to higher average property, plant and equipment balances.

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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 December 31, 2025, the WNA reduced earnings by approximately $0.8 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 quarter ended December 31, 2024, the WNA preserved earnings of approximately $2.0 million and $1.2 million, respectively, in the Utility segment’s New York and Pennsylvania rate jurisdictions, as the weather was warmer than normal on a cycle-bill basis in both jurisdictions.

For the quarter ended March 31, 2026, the WNA reduced earnings by approximately $1.1 million in both 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 quarter ended March 31, 2025, the WNA preserved earnings of approximately $0.6 million in the Utility segment’s New York rate jurisdiction, as the weather was warmer than normal on a cycle-bill basis.

The earnings preserved by the WNA in the Utility segment's Pennsylvania rate jurisdiction for the quarter ended March 31, 2025 were negligible.

The Utility segment’s earnings for the six months ended March 31, 2026 were $99.4 million, an increase of $3.4 million when compared with earnings of $96.0 million for the six months ended March 31, 2025.

The increase can be attributed to the following factors:

Impact of new base rates in New York $ 6.1

Impact of regulatory revenue adjustments 4.6 (1)

Impact of higher customer usage 1.6

Higher other operating revenues 1.3

Higher operating expenses (6.7) (2)

Higher depreciation expense (2.5) (3)

Higher interest expense (0.9) (4)

Other items (0.1)

(2) The increase in operating expenses is largely attributable to higher personnel costs and higher uncollectible expenses as a result of higher operating revenue.

(3) The increase in depreciation expense is attributable to higher average property, plant and equipment balances.

(4) The increase in interest expenses is mainly attributed to an increase in long-term intercompany debt balances.

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For the six months ended March 31, 2026, the WNA reduced earnings by approximately $1.9 million and $2.0 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 six months ended March 31, 2025, the WNA preserved earnings in the Utility segment’s New York rate jurisdiction of approximately $2.6 million and preserved earnings in the Utility segment’s Pennsylvania rate jurisdiction of approximately $1.2 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 December 31, 2025, an increase in net loss of $7.4 million when compared with a net loss of $0.3 million for the quarter ended December 31, 2024.

The increase in net loss was primarily attributable to costs associated with the Company's planned acquisition of CenterPoint Ohio ($5.9 million).

All Other and Corporate operations reported a net loss of $1.3 million for the quarter ended March 31, 2026, a reduction of $1.8 million when compared with a net loss of $3.1 million for the quarter ended March 31, 2025.

The reduction was primarily attributable to a net interest benefit arising from the December 2025 equity issuance ($2.6 million).

While the proceeds of the equity issuance are intended for the pending acquisition of CenterPoint Ohio, in the short term those proceeds have created some interest income and, to a larger extent, have reduced borrowings and interest expense.

Additional factors contributing to the reduction in net loss were an increase in income from life insurance policies ($1.1 million) and higher income from unconsolidated subsidiaries ($1.2 million).

Partially offsetting these decreases to net loss were a decrease in interest income earned on temporary cash investments ($0.7 million), external costs associated with the Company's planned acquisition of CenterPoint Ohio ($1.9 million) and higher internal labor costs ($0.6 million).

Refer to Part I, Item 1 at Note 2 - Pending Acquisition for further discussion of this acquisition.

Additional contributing factors to the increase in net loss were a decrease in the cash surrender value of life insurance policies ($0.9 million) and higher operating expenses ($0.9 million), primarily due to increased legal and consulting fees and outside service costs.

For the six months ended March 31, 2026, All Other and Corporate operations reported a net loss of $9.0 million, an increase of $5.6 million when compared with a net loss of $3.4 million for the six months ended March 31, 2025.

The increase was primarily attributable to external costs associated with the Company's planned acquisition ($7.8 million), as mentioned above, and higher operating expenses ($2.0 million) primarily attributable to an increase in internal labor costs, employee benefits and legal and consulting fees.

Partially offsetting these increases, there was a net interest benefit from the December 2025 equity issuance ($3.0 million), as mentioned above, and higher income from unconsolidated subsidiaries ($1.2 million).

Other Income (Deductions)

Net other income on the Consolidated Statements of Income was $8.2 million for the quarter ended December 31, 2025, compared to net other income of $7.7 million for the quarter ended December 31, 2024, for an increase of $0.5 million.

This increase can be attributed primarily to a $1.1 million increase in interest income.

Partially offsetting this increase was a $0.7 million decrease in non-service pension and post-retirement benefit income.

Net other income on the Consolidated Statements of Income was $17.0 million for the quarter ended March 31, 2026, compared to net other income of $15.2 million for the quarter ended March 31, 2025, for an increase of $1.8 million.

This increase can be attributed primarily to higher income from unconsolidated subsidiaries of $1.4 million and a $1.1 million increase in income from life insurance policies.

Partially offsetting these increases was a $0.8 million decrease in non-service pension and post-retirement benefit income.

Net other income on the Consolidated Statements of Income was $25.2 million for the six months ended March 31, 2026, compared to net other income of $23.0 million for the six months ended March 31, 2025, for an increase of $2.2 million.

This increase can be attributed primarily to higher income from unconsolidated subsidiaries of $1.6 million, along with an increase in interest income on deferred gas costs of $1.2 million and the nonrecurrence of a $0.7 million revaluation adjustment for contingent consideration that reduced other income during the six months ended March 31, 2025.

Partially offsetting these increases was a $1.4 million decrease in non-service pension and post-retirement benefit income.

Interest Expense on Long-Term Debt

Interest expense on long-term debt on the Consolidated Statement of Income decreased $9.6 million for the quarter ended March 31, 2026 as compared to the quarter ended March 31, 2025.

For the six months ended March 31, 2026, interest expense on long-term debt decreased $9.4 million as compared with the six months ended March 31, 2025.

The decrease in interest expense for both the quarter and six months ended March 31, 2026 was due to lower debt outstanding.

The Company repaid a $300 million delayed draw term loan in January 2026.

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.

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Other Interest Expense

Other interest expense on the Consolidated Statement of Income increased $5.5 million for the quarter ended December 31, 2025 as compared to the quarter ended December 31, 2024.

These increases are primarily due to financing costs incurred associated with the Company's acquisition of CenterPoint Ohio's natural gas utility.

Other interest expense on the Consolidated Statement of Income decreased $1.4 million for the quarter ended March 31, 2026 as compared to the quarter ended March 31, 2025.

This decrease was primarily due to lower average short term debt balances.

For the six months ended March 31, 2026, other interest expense increased $4.0 million as compared to the six months ended March 31, 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 three-month period ended December 31, 2025 consisted of cash provided by operating activities and net proceeds from the issuance of common stock.

The Company’s primary source of cash during the three-month period ended December 31, 2024 consisted of cash provided by operating activities and net proceeds from short-term borrowings.

The Company’s primary source of cash during the six-month period ended March 31, 2026 consisted of cash provided by operating activities and net proceeds from the issuance of common stock.

The Company’s primary source of cash during the six-month period ended March 31, 2025 consisted of cash provided by operating activities and net proceeds from short-term and 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 and short-term and long-term borrowings to fund the Company's capital expenditures.

The Company has repaid the $300.0 million delayed draw term loan that was expected to mature in February 2026.

Looking forward to 2027, based on current commodity prices, cash provided by operating activities is again expected to exceed capital expenditures.

These cash flow projections include the impact of the CenterPoint Ohio acquisition but do not reflect the impact of other acquisitions or divestitures that may arise in the future.

During the remainder of 2026, the Company expects to use cash provided by operating activities and short-term borrowings to fund the Company's capital expenditures.

In January 2026, the Company repaid the $300.0 million delayed draw term loan that was scheduled to mature in February 2026.

Looking forward to 2027, based on current forward commodity prices, cash provided by operating activities is expected to exceed capital expenditur es.

These cash flow projections do not include the impact of the CenterPoint Ohio acquisition, the repayment of the Company's $300.0 million of 5.50% notes with a maturity date in 2026 or the impact of other acquisitions or divestitures that may arise in the future.

Operating Cash Flow

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Non-cash items include depreciation, depletion and amortization, impairment of assets, deferred income taxes and stock-based compensation.

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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.

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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 $274.9 million for the three months ended December 31, 2025, an increase of $54.8 million compared with $220.1 million provided by operating activities for the three months ended December 31, 2024.

The increase in cash provided by operating activities primarily reflects higher cash provided by operating activities in the Integrated Upstream and Gathering segment, partially offset by lower cash provided by operating activities in the Utility segment.

The increase in the Integrated Upstream and Gathering segment is primarily due to higher natural gas prices and production in the Appalachian region combined with the timing of cash receipts and hedge settlements associated with that production.

The decrease in the Utility segment is primarily due to higher natural gas prices and throughput combined with the timing of the associated gas cost recovery.

Net cash provided by operating activities totaled $657.3 million for the six months ended March 31, 2026, an increase of $183.4 million compared with $473.9 million provided by operating activities for the six months ended March 31, 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

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natural gas prices and production in the Appalachian region combined with the timing of cash receipts and hedge settlements associated with that production.

Investing Cash Flow

Expenditures for Long-Lived Assets

The Company’s expenditures for long-lived assets totaled $222.7 million during the three months ended December 31, 2025 and $192.1 million during the three months ended December 31, 2024.

The Company’s expenditures for long-lived assets totaled $455.7 million during the six months ended March 31, 2026 and $373.1 million during the six months ended March 31, 2025.

The table below presents these expenditures:

Total Expenditures for Long-Lived Assets

Three Months Ended December 31, 2025 2024 Increase (Decrease)

Six Months Ended March 31, 2026 2025 Increase (Decrease)

Integrated Upstream and Gathering:

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Capital Expenditures 0.4 0.4 —

Eliminations (0.5) — (0.5)

$ 455.7 $ 373.1 $ 82.6

(1) At December 31, 2025, capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment and the Utility segment included $55.5 million, $8.1 million and $6.8 million, respectively, of non-cash capital expenditures.

(1) At March 31, 2026, capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment and the Utility segment included $71.6 million, $5.1 million and $6.0 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.

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(2) At December 31, 2024, capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment and the Utility segment included $62.3 million, $4.4 million and $4.9 million, respectively, of non-cash capital expenditures.

(2) At March 31, 2025, capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment and the Utility segment included $51.6 million, $2.4 million and $4.8 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 three months ended December 31, 2025 were primarily upstream well drilling and completion expenditures in the Appalachian region, including $90.9 million spent in the Utica Shale area and $33.5 million spent in the Marcellus Shale area.

The Integrated Upstream and Gathering segment capital expenditures for the six months ended March 31, 2026 were primarily upstream well drilling and completion expenditures in the Appalachian region, including $194.6 million spent in the Utica Shale area and $68.4 million spent in the Marcellus Shale area.

These amounts included approximately $188.9 million spent to develop proved undeveloped reserves.

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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 three months ended December 31, 2024 were primarily upstream well drilling and completion expenditures in the Appalachian region, including $90.9 million spent in the Utica Shale area and $27.5 million spent in the Marcellus Shale area.

The Integrated Upstream and Gathering segment capital expenditures for the six months ended March 31, 2025 were primarily upstream well drilling and completion expenditures in the Appalachian region, including $137.8 million spent in the Utica Shale area and $84.3 million spent in the Marcellus Shale area.

These amounts included approximately $105.4 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 gathering system.

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 three months ended December 31, 2025 and December 31, 2024 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 three months ended December 31, 2025 included expenditures related to Supply's Corporation's Tioga Pathway Project ($5.4 million) and Shippingpoint Lateral Project ($2.4 million).

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.

The Pipeline and Storage segment capital expenditures for the six months ended March 31, 2026 and March 31, 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.

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addition, the Pipeline and Storage segment capital expenditures for the six months ended March 31, 2026 included expenditures related to Supply Corporation's Tioga Pathway Project ($8.4 million) and Shippingpoint Lateral Project ($12.6 million), both of which are discussed below.

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.

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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 is expected to commence in February 2026.

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 December 31, 2025, approximately $10.5 million has been capitalized as Construction Work in Progress for this project.

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 is expected to support a co-located data center (the

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“Shippingport Lateral Project”).

In order to provide this new natural gas transportation capacity, Supply Corporation expects to 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.

As of March 31, 2026, approximately $13.5 million has been capitalized as Construction Work in Progress for this project.

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 Shippingport Power Station, LLC, the facility 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.

As of December 31, 2025, approximately $2.6 million has been spent on this project, including $0.1 million spent to study the project that is included in Deferred Charges on the Consolidated Balance Sheet.

The remaining $2.5 million spent on the project has been capitalized as Construction Work in Progress.

The majority of the Utility segment capital expenditures for the three months ended December 31, 2025 and December 31, 2024 were made for main and service line improvements and replacements that enhance the reliability and safety of the system and reduce emissions.

The project obtained FERC authorization on November 7, 2025 and construction commenced in March 2026.

As of March 31, 2026, approximately $12.8 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 94,000 Dth per day of additional natural gas transportation capacity from a new interconnection on the southern portion of Supply’s Line N system in Greene County, Pennsylvania to an existing Supply Corporation interconnection with Tennessee Gas Pipeline Company, LLC at Mercer.

In April 2026, Supply Corporation executed a long-term precedent agreement with a shipper 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 $93 million.

As of March 31, 2026, $0.3 million has been spent to study this project, all of which has been included in Deferred Charges on the Consolidated Balance Sheet at March 31, 2026.

The majority of the Utility segment capital expenditures for the six months ended March 31, 2026 and March 31, 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.

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Project Funding

During the quarter ended December 31, 2025 and fiscal 2025, the Company has financed capital expenditures with cash from operations and short-term debt.

During the six months ended March 31, 2026 and fiscal 2025, the Company has financed capital expenditures with cash from operations and short-term debt.

Going forward, the Company expects to use cash from operations, equity proceeds, and short-term or long-term borrowings, as needed, to finance capital expenditures.

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Financing Cash Flow

Consolidated short-term debt decreased $60.2 million when comparing the balance sheet at December 31, 2025 to the balance sheet at September 30, 2025.

The maximum amount of short-term debt outstanding during the three months ended December 31, 2025 was $311.0 million.

Consolidated short-term debt decreased $108.9 million when comparing the balance sheet at March 31, 2026 to the balance sheet at September 30, 2025.

The maximum amount of short-term debt outstanding during the six months ended March 31, 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 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 December 31, 2025, the Company had outstanding commercial paper of $90.0 million and did not have any short-term notes payable to banks.

As of March 31, 2026, the Company had outstanding commercial paper of $41.3 million and did not have any short-term notes payable to banks.

On October 20, 2025, the Company entered into a Securities Purchase Agreement (the “Purchase Agreement”) with CenterPoint Energy Resources Corp.

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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.

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The borrowings under the Seller Note Facility will bear interest at a rate of 6.5% per annum.

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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.

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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.

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After deducting placement fees, the net proceeds to the Company amounted to $338.4 million.

The Company is using the net proceeds from the issuance for general corporate purposes, including to finance a portion of the Purchase Price for the Transaction.

The net proceeds of the issuance reduced the commitments under the Term Loan Facility to $1.08 billion.

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Any definitive financing documentation for the Term Loan Facility or 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 respective funding dates of the Term Loan

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Facility and the Bridge Facility, such that borrowings under the facilities would not be incurred.

The Company expects to execute permanent financing prior to the respective funding dates of the Term Loan Facility and the Bridge Facility, such that borrowings under the facilities would not be incurred.

There can be no assurance, however, such permanent financing will occur and any such expectation is subject to market conditions.

The Company is a party to a syndicated Credit Agreement (as amended from time to time, the “Credit Agreement”) that provides a $1.0 billion unsecured committed revolving credit facility.

In January 2025, the Company and the banks in the syndicate consented to a second one-year extension of the maturity date of the Credit Agreement, such that the Company has aggregate commitments available in the full amount of $1.0 billion through February 23, 2029.

In May 2025, the total lenders under the Credit Agreement increased to twelve as a new lender joined the syndicate, assuming a portion of an existing lender's commitment.

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 uncommitted lines of credit with financial institutions for general corporate purposes.

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.

The Company anticipates that its uncommitted lines of credit generally will be renewed or substantially replaced by similar lines.

The uncommitted credit lines are revocable at the option of the financial institution and are reviewed

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on an annual basis.

Other financial institutions may also provide the Company with uncommitted or discretionary lines of credit in the future.

The Company entered into a term loan agreement (the “Term Loan Agreement”) on February 14, 2024, with six of the 12 banks that are lenders under the Credit Agreement.

As of January 22, 2026, the Company repaid the $300.0 million drawn under the Term Loan Agreement, and the agreement was therefore terminated.

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.

In April 2024, pursuant to the delayed draw mechanism, the Company elected to draw a total of $300.0 million under the facility.

After deducting debt issuance costs, the net proceeds to the Company amounted to $299.4 million.

Borrowings under the Term Loan Agreement bear interest at a rate equal to SOFR for the applicable interest period, plus an adjustment of 0.10%, plus a spread of 1.375%.

Both the Credit Agreement and the Term Loan Agreement provide that the Company’s debt to capitalization ratio will not exceed 0.65 at the last day of any fiscal quarter.

For purposes of calculating the debt to capitalization ratio, the Company’s total capitalization will be increased by adding back 50% of the aggregate after-tax amount of non-cash charges directly arising from any ceiling test impairment occurring on or after July 1, 2018, not to exceed $400 million.

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.

Since that date, the Company recorded non-cash, after-tax ceiling test impairments totaling $797.0 million.

As a result, at December 31, 2025, $398.5 million was added back to the Company’s total capitalization for purposes of calculating the debt to capitalization ratio under the Credit Agreement and the Term Loan Agreement.

As a result, at March 31, 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:

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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, pursuant to amendments to the Credit Agreement and Term Loan Agreement entered into as of November 6, 2025, 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 December 31, 2025, the Company’s debt to capitalization ratio, as calculated under the agreements, was 0.41.

The constraints specified in the Credit Agreement and the Term Loan Agreement would have permitted an additional $4.54 billion in short-term and/or long-term debt to be outstanding at December 31, 2025 before the Company’s debt to capitalization ratio exceeded 0.65.

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 March 31, 2026, the Company’s debt to capitalization ratio, as calculated under the Credit Agreement, was 0.37.

The constraints specified in the Credit Agreement would have permitted an additional $5.26 billion in short-term and/or long-term debt to be outstanding at March 31, 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.

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However, the Company expects that it could borrow under its credit facilities or rely upon other liquidity sources.

The Credit Agreement and the Term Loan Agreement each contain a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the

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Credit Agreement or Term Loan Agreement, as applicable.

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.

The Current Portion of Long-Term Debt at December 31, 2025 consisted of a $300.0 million long-term delayed draw term loan scheduled to mature in February 2026 that was repaid in January 2026 and $300.0 million of 5.50% notes with a maturity date in October 2026.

The Current Portion of Long-Term Debt at September 30, 2025 consisted of the aforementioned $300.0 million long-term delayed draw term loan with a maturity date in February 2026.

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

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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.

The Current Portion of Long-Term Debt at March 31, 2026 consisted of $300.0 million of 5.50% notes with a maturity date in October 2026.

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 4.85% at December 31, 2025 and 4.83% at December 31, 2024.

The Company’s embedded cost of long-term debt was 4.81% at March 31, 2026 and 4.97% at March 31, 2025.

OTHER MATTERS

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While these normal-course matters could have a material effect on earnings and cash flows in the period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.

The Company did not make any contributions to its tax-qualified, noncontributory defined benefit retirement plan (Retirement Plan) during the three months ended December 31, 2025, 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 three months ended December 31, 2025, and does not anticipate making any such contributions during the remainder of fiscal 2026.

The Company did not make any contributions to its tax-qualified, noncontributory defined benefit retirement plan (Retirement Plan) during the six months ended March 31, 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 six months ended March 31, 2026, and does not anticipate making any such contributions during the remainder of fiscal 2026.

Market Risk Sensitive Instruments

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The authoritative guidance for fair value measurements and disclosures requires consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities.

At December 31, 2025, 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.

At March 31, 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.

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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,

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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.

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New York Jurisdiction

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The Company is also proposing reactivation of the OPEB surcredit (Rider I) to refund $7.2 million for customer bill relief.

The filing will be suspended for seven months by operation of law unless directed otherwise by the PaPUC.

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.

On April 10, 2024, Distribution Corporation filed with the PaPUC a petition for approval of a distribution system improvement charge ("DSIC") to recover, between base rate cases, capital expenses related to eligible property constructed or installed to rehabilitate, improve and replace portions of the Company’s natural gas distribution system.

The DSIC petition was approved by the PaPUC on December 5, 2024, and on January 1, 2025, the Company initiated recovery of eligible costs on incremental rate base added after September 30, 2024.

During the quarter ended December 31, 2025, Distribution Corporation recovered $1.1 million from customers.

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.

During the quarter ended March 31, 2026, Distribution Corporation recovered $2.8 million from customers.

The DSIC cap has been met and the Company is unable to earn a return on incremental plant investments.

The DSIC will be reset to zero when new base rates become effective as a result of the Company's recent rate filing.

Pipeline and Storage

Supply Corporation’s rate settlement was approved June 11, 2024 with rates effective February 1, 2024, and provides that Supply Corporation may make a rate filing for new rates to be effective at any time.

As well, any party can make a filing under NGA Section 5.

Supply Corporation has no rate case currently on file.

Supply Corporation filed an NGA Section 4 rate case at FERC on April 30, 2026 proposing rate increases to be effective November 1, 2026.

The proposal also includes, among other things, a modernization cost recovery mechanism.

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.

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In 2021, the Company set methane intensity reduction targets at each of its businesses, an absolute greenhouse gas emissions reduction target for the consolidated Company, and greenhouse gas reduction targets associated with the Company’s utility delivery system.

In 2022, the Company began

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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.

In 2022, the Company began measuring progress against these reduction targets.

The Company's ability to estimate accurately the time, costs and resources

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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.”

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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 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, is developing a cap-and-invest program in the state, although issuance of certain key regulations necessary to implement the program has been delayed.

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.

In October 2025, a New York State Supreme Court judge issued an order requiring the NYDEC to promulgate regulations in accordance with the CLCPA by February 6, 2026.

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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.

From time to time, the Company may publish or otherwise make available

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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

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in this report, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new authoritative accounting and reporting guidance, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements.

Certain statements contained in this report, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new authoritative accounting and reporting guidance, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements.

The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished.

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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;

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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;

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Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits;

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-Q

Item 2. Management’s Discussion and Analysis