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Item 1. Financial Statements

2026-01-29 compared with 2025-07-31 · 238 added, 316 removed, 507 unchanged (52% of the section changed)

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Three Months Ended

June 30, Nine Months Ended

(Thousands of U.S.

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Utility Revenues $ 259,047 $ 228,424

Exploration and Production and Other Revenues 303,883 220,905 864,701 739,537

Pipeline and Storage and Gathering Revenues 70,501 71,679 217,116 216,228

Integrated Upstream and Gathering Revenues 323,223 252,308

Pipeline and Storage Revenues 69,237 68,750

651,507 549,482

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Utility 59,897 55,244

Exploration and Production and Other 35,272 35,148 103,874 102,768

Pipeline and Storage and Gathering 41,679 40,019 119,982 114,321

Integrated Upstream and Gathering and Other 56,306 42,905

Pipeline and Storage 26,786 26,577

Property, Franchise and Other Taxes 24,764 22,056

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375,384 463,291

Operating Income (Loss) 230,252 ( 51,440 ) 633,694 406,294

Operating Income 276,123 86,191

Other Income (Expense):

Other Income (Deductions) 8,534 3,188 31,486 12,989

Other Income 8,233 7,720

Interest Expense on Long-Term Debt ( 33,513 ) ( 33,362 )

Other Interest Expense ( 9,861 ) ( 4,381 )

Income (Loss) Before Income Taxes 200,897 ( 82,469 ) 544,791 315,242

Income Tax Expense (Benefit) 51,079 ( 28,311 ) 133,629 70,108

Net Income (Loss) Available for Common Stock 149,818 ( 54,158 ) 411,162 245,134

Income Before Income Taxes 240,982 56,168

Income Tax Expense 59,337 11,182

Net Income Available for Common Stock 181,645 44,986

EARNINGS REINVESTED IN THE BUSINESS

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Dividends on Common Stock ( 50,834 ) ( 46,671 )

Balance at June 30 $ 1,953,533 $ 1,970,384 $ 1,953,533 $ 1,970,384

Earnings (Loss) Per Common Share:

Net Income (Loss) Available for Common Stock $ 1.66 $ ( 0.59 ) $ 4.54 $ 2.67

Net Income (Loss) Available for Common Stock $ 1.64 $ ( 0.59 ) $ 4.51 $ 2.65

Balance at December 31 $ 2,143,340 $ 1,698,648

Earnings Per Common Share:

Net Income Available for Common Stock $ 1.99 $ 0.50

Net Income Available for Common Stock $ 1.98 $ 0.49

Weighted Average Common Shares Outstanding:

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Three Months Ended

June 30, Nine Months Ended

(Thousands of U.S.

Dollars) 2025 2024

Net Income (Loss) Available for Common Stock $ 149,818 $ ( 54,158 ) $ 411,162 $ 245,134

Net Income Available for Common Stock $ 181,645 $ 44,986

Other Comprehensive Income (Loss), Before Tax:

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Consolidated Statements of Cash Flows

Nine Months Ended

Three Months Ended

(Thousands of U.S.

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Deferred Income Taxes 34,277 ( 5,385 )

Premiums Paid on Early Redemption of Debt 2,385 —

Stock-Based Compensation 4,094 4,705

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Changes in Notes Payable to Banks and Commercial Paper ( 60,200 ) 109,300

Net Proceeds from Issuance of Long-Term Debt 988,731 299,396

Shares Repurchased Under Repurchase Plan — ( 33,524 )

Reduction of Long-Term Debt ( 1,004,086 ) —

Dividends Paid on Common Stock ( 48,353 ) ( 46,872 )

Net Proceeds from Common Stock Sale 347,106 —

Net Repurchases of Common Stock Under Stock and Benefit Plans ( 6,356 ) ( 3,971 )

Net Cash Used in Financing Activities ( 243,217 ) ( 156,477 )

Net Cash Provided by Financing Activities 232,197 24,933

Net Increase in Cash and Cash Equivalents 228,232 10,472

Cash and Cash Equivalents at October 1 43,166 38,222

Cash and Cash Equivalents at June 30 $ 39,317 $ 81,414

Cash and Cash Equivalents at December 31 $ 271,398 $ 48,694

Supplemental Disclosure of Cash Flow Information

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Non-Cash Capital Expenditures $ 70,359 $ 71,616

Non-Cash Financing Activities:

Non-Cash Accrued Placement Fees from Common Stock Sale $ 8,531 $ —

See Notes to Condensed Consolidated Financial Statements

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Actual results could differ from those estimates.

Reclassifications.

As reported in the Company's 2025 Form 10-K, during the quarter ended September 30, 2025, the segment reporting structure was modified to merge the Exploration and Production segment and Gathering segment into one reportable segment called Integrated Upstream and Gathering.

As a result, revenue and operation and maintenance expense line items on the consolidated statements of income in prior periods have been reclassified to conform to the current year presentation.

Additional discussion is provided at Note 9 — Business Segment Information.

Earnings for Interim Periods.

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The consolidated financial statements for the year ended September 30, 2026 will be audited by the Company's independent registered public accounting firm after the end of the fiscal year.

The earnings for the nine months ended June 30, 2025 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2025.

The earnings for the three months ended December 31, 2025 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2026.

Most of the business of the Utility segment is seasonal in nature and is influenced by weather conditions.

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Consolidated Statements of Cash Flows.

The Statement of Cash Flows for the nine months ended June 30, 2025 and nine months ended June 30, 2024 reconciles the net increase in cash and cash equivalents, which consists solely of cash and temporary cash investments for the periods presented.

The Company did not have any restricted cash at June 30, 2025, October 1, 2024, June 30, 2024 or October 1, 2023.

The Statement of Cash Flows for the three months ended December 31, 2025 and the three months ended December 31, 2024 reconciles the net increase in cash and cash equivalents, which consists solely of cash and temporary cash investments for the periods presented.

The Company did not have any restricted cash at December 31, 2025, October 1, 2025, December 31, 2024 or October 1, 2024.

The Company considers all highly liquid debt instruments purchased with a maturity date of generally three months or less to be equivalents.

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This change in policy was initiated to better match the timing of write-offs with the recovery of uncollectible expense in rates and resulted in a one-time cumulative adjustment to the allowance during the quarter ended March 31, 2025.

Activity in the allowance for uncollectible accounts for the nine months ended June 30, 2025 and 2024 are as follows (in thousands):

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Activity in the allowance for uncollectible accounts for the three months ended December 31, 2025 and 2024 are as follows (in thousands):

Balance at Beginning of Period Additions Charged to Costs and Expenses Discounts on Purchased Receivables Net Accounts Receivable Written-Off Balance at End of Period

Nine Months Ended June 30, 2025

Three Months Ended December 31, 2025

Allowance for Uncollectible Accounts $ 17,099 $ 5,214 $ 121 $ ( 4,930 ) $ 17,504

Nine Months Ended June 30, 2024

Three Months Ended December 31, 2024

Allowance for Uncollectible Accounts $ 26,194 $ 4,605 $ 107 $ ( 2,522 ) $ 28,384

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Gas Stored Underground.

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Gas stored underground normally declines during the first and second quarters of the year as storage quantities are withdrawn and increases in the third and fourth quarters as storage quantities are replenished.

In the Utility segment, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption “Other Accruals and Current Liabilities.” Such reserve, which amounted to $ 12.7 million at June 30, 2025, is reduced to zero by September 30 of each year as the inventory is replenished.

In the Utility segment, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption “Other Accruals and Current Liabilities.” Such reserve, which amounted to $ 2.8 million at December 31, 2025, is reduced to zero by September 30 of each year as the inventory is replenished.

Property, Plant and Equipment.

In the Company’s Exploration and Production segment, property acquisition, exploration and development costs are capitalized under the full cost method of accounting.

In the Company’s Integrated Upstream and Gathering segment, upstream property acquisition, exploration and development costs are accounted for under the full cost method of accounting.

Under this methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities.

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The Company does not recognize any gain or loss on the sale or other disposition of properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves attributable to a cost center.

The Company's capitalized costs relating to exploration and production activities, net of accumulated depreciation, depletion and amortization, were $ 2.32 billion and $ 2.28 billion at June 30, 2025 and September 30, 2024, respectively.

The Company's capitalized costs relating to exploration and production activities, net of accumulated depreciation, depletion and amortization, were $ 2.51 billion and $ 2.46 billion at December 31, 2025 and September 30, 2025, respectively.

Capitalized costs include costs related to unproved properties, which are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired.

Such costs amounted to $ 132.6 million and $ 201.0 million at June 30, 2025 and September 30, 2024, respectively.

Such costs amounted to $ 105.7 million and $ 112.4 million at December 31, 2025 and September 30, 2025, respectively.

All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred.

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If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent non-cash impairment is required to be charged to earnings in that quarter.

At June 30, 2025, the ceiling exceeded the book value of the exploration and production properties by approximately $ 798.8 million.

At December 31, 2025, the ceiling exceeded the book value of the exploration and production properties by approximately $ 1.3 billion.

The book value of the exploration and production properties exceeded the ceiling at December 31, 2024.

As such, the Company recognized a non-cash, pre-tax impairment charge of $ 108.3 million for the quarter ended December 31, 2024.

As such, the Company recognized a non-cash, pre-tax ceiling test impairment charge in the Integrated Upstream and Gathering segment of $ 108.3 million for the quarter ended December 31, 2024.

A deferred income tax benefit of $ 29.2 million related to the non-cash impairment charge was also recognized for the quarter ended December 31, 2024.

The estimated future net cash flows were increased by $ 338.6 million for hedging under the ceiling test at June 30, 2025.

The Exploration and Production segment also has items of property, plant and equipment that are accounted for outside of the provisions of the full cost method of accounting.

As discussed in Note 3 – Fair Value Measurements, an impairment charge related to certain water disposal assets was recorded at December 31, 2024.

The principal assets of the Utility, Pipeline and Storage and Gathering segments, consisting primarily of gas distribution pipelines, transmission pipelines, storage facilities, gathering lines and compressor stations, are recorded at historical cost.

There were no indications of any impairments to property, plant and equipment in the Utility, Pipeline and Storage and Gathering segments at June 30, 2025.

In adjusting estimated future net cash flows for hedging under the ceiling test at December 31, 2025, estimated future net cash flows were increased by $ 170.7 million.

The Integrated Upstream and Gathering segment also has items of property, plant and equipment that are accounted for outside of the provisions of the full cost method of accounting, including water disposal assets used in its upstream operations as well as gathering lines and compressor stations associated with its gathering operations, all of which are recorded at

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historical cost.

As discussed in Note 4 – Fair Value Measurements, an impairment charge related to certain water disposal assets was recorded in the Integrated Upstream and Gathering segment at December 31, 2024.

The principal assets of the Utility and Pipeline and Storage segments, consisting primarily of gas distribution pipelines, transmission pipelines, storage facilities and compressor stations, are recorded at historical cost.

There were no indications of any impairments to property, plant and equipment in the Utility and Pipeline and Storage segments at December 31, 2025.

Accumulated Other Comprehensive Income (Loss).

The components of Accumulated Other Comprehensive Income (Loss) and changes for the nine months ended June 30, 2025 and 2024, net of related tax effect, are as follows (amounts in parentheses indicate debits) (in thousands):

The components of Accumulated Other Comprehensive Income (Loss) and changes for the three months ended December 31, 2025 and 2024, net of related tax effect, are as follows (amounts in parentheses indicate debits) (in thousands):

Gains and Losses on Derivative Financial Instruments Funded Status of the Pension and Other Post-Retirement Benefit Plans Total

Three Months Ended June 30, 2025

Balance at April 1, 2025 $ ( 151,700 ) $ ( 71,275 ) $ ( 222,975 )

Other Comprehensive Gains and Losses Before Reclassifications

108,818 — 108,818

Amounts Reclassified From Other Comprehensive Loss ( 1,650 ) — ( 1,650 )

Balance at June 30, 2025 $ ( 44,532 ) $ ( 71,275 ) $ ( 115,807 )

Nine Months Ended June 30, 2025

Three Months Ended December 31, 2025

Balance at October 1, 2025 $ 19,950 $ ( 79,172 ) $ ( 59,222 )

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Amounts Reclassified From Other Comprehensive Loss ( 9,720 ) — ( 9,720 )

Balance at June 30, 2025 $ ( 44,532 ) $ ( 71,275 ) $ ( 115,807 )

Three Months Ended June 30, 2024

Balance at April 1, 2024 $ 135,023 $ ( 59,683 ) $ 75,340

Other Comprehensive Gains and Losses Before Reclassifications

( 15,850 ) — ( 15,850 )

Amounts Reclassified From Other Comprehensive Income ( 54,440 ) — ( 54,440 )

Balance at June 30, 2024 $ 64,733 $ ( 59,683 ) $ 5,050

Nine Months Ended June 30, 2024

Balance at December 31, 2025 $ 46,182 $ ( 79,172 ) $ ( 32,990 )

Three Months Ended December 31, 2024

Balance at October 1, 2024 $ 55,799 $ ( 71,275 ) $ ( 15,476 )

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( 39,113 ) — ( 39,113 )

Amounts Reclassified From Other Comprehensive Income ( 112,139 ) — ( 112,139 )

Balance at June 30, 2024 $ 64,733 $ ( 59,683 ) $ 5,050

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Amounts Reclassified From Other Comprehensive Loss ( 21,564 ) — ( 21,564 )

Balance at December 31, 2024 $ ( 4,878 ) $ ( 71,275 ) $ ( 76,153 )

Reclassifications Out of Accumulated Other Comprehensive Income (Loss).

The details about the reclassification adjustments out of accumulated other comprehensive income (loss) for the nine months ended June 30, 2025 and 2024 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands):

The details about the reclassification adjustments out of accumulated other comprehensive income (loss) for the three months ended December 31, 2025 and 2024 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands):

Details About Accumulated Other Comprehensive Income (Loss) Components Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) Affected Line Item in the Statement Where Net Income is Presented

Three Months Ended

June 30, Nine Months Ended

2025 2024 2025 2024

Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:

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$ 9,720 $ 21,564 Net of Tax

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Other Current Assets .

The components of the Company’s Other Current Assets are as follows (in thousands):

At June 30, 2025 At September 30, 2024

At December 31, 2025 At September 30, 2025

Prepayments $ 13,854 $ 16,477

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The components of the Company’s Other Accruals and Current Liabilities are as follows (in thousands):

At June 30, 2025 At September 30, 2024

At December 31, 2025 At September 30, 2025

Accrued Capital Expenditures $ 47,178 $ 45,932

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Federal Income Taxes Payable 5,384 —

State Income Taxes Payable 4,676 —

Pennsylvania Impact Fee 19,955 14,923

Non-Qualified Benefit Plan Liability 11,567 11,567

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For purposes of determining earnings per common share, the potentially dilutive securities the Company had outstanding were restricted stock units and performance shares.

For the quarter and nine months ended June 30, 2025, the diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method.

For the quarter ended December 31, 2025, the diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method.

Restricted stock units and performance shares that are antidilutive are excluded from the calculation of diluted earnings per common share.

There were 1,126 securities and 1,097 securities excluded as being antidilutive for the quarter and nine months ended June 30, 2025, respectively.

There were 335 securities

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excluded as being antidilutive for the nine months ended June 30, 2024.

As the Company recognized a net loss for the quarter ended June 30, 2024, in accordance with accounting guidance, all dilution associated with restricted stock units and performance shares in the amount of 567,681 shares, was excluded from the earnings per share calculation for the quarter ended June 30, 2024.

There were 30 securities and four securities excluded as being antidilutive for the quarters ended December 31, 2025 and December 31, 2024, respectively.

Share Repurchases.

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The repurchases are accounted for on the date the share repurchase is traded as an adjustment to common stock (at par value) with the excess repurchase price allocated between paid in capital and retained earnings.

Refer to Note 6 – Capitalization for further discussion of the Company's share repurchase program.

Stock-Based Compensation.

The Company granted 239,042 performance shares during the nine months ended June 30, 2025.

The weighted average fair value of such performance shares was $ 55.43 per share for the nine months ended June 30, 2025.

The Company granted 137,995 performance shares during the quarter ended December 31, 2025.

The weighted average fair value of such performance shares was $ 62.07 per share for the quarter ended December 31, 2025.

Performance shares are an award constituting units denominated in common stock of the Company, the number of which may be adjusted over a performance cycle based upon the extent to which performance goals have been satisfied.

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The performance shares do not entitle the participant to receive dividends during the vesting period.

The performance shares granted during the nine months ended June 30, 2025 include awards that must meet a performance goal related to either relative total return on capital over a three-year performance cycle ("ROC Performance Shares"), methane intensity and greenhouse gas emissions reductions over a three-year performance cycle ("Emissions Performance Shares") or relative total shareholder return over a three-year performance cycle ("TSR Performance Shares").

The performance goal related to the ROC Performance Shares over the three-year performance cycle is the Company’s total return on capital relative to the total return on capital of other companies in a group selected by the Compensation Committee (“Report Group”).

Total return on capital for a given company means the average of the Report Group companies’ returns on capital for each twelve-month period corresponding to each of the Company’s fiscal years during the performance cycle, based on data reported for the Report Group companies in the Bloomberg database.

The number of these ROC Performance Shares that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company.

The fair value of the ROC Performance Shares is calculated by multiplying the expected number of shares that will be issued by the average market price of Company common stock on the date of grant reduced by the present value of forgone dividends over the vesting term of the award.

The fair value is recorded as compensation expense over the vesting term of the award.

The performance goal related to the Emissions Performance Shares over the three-year performance cycle consists of two parts:

reductions in the rates of intensity of methane emissions for each of the Company's operating segments, and reduction of the consolidated Company's total greenhouse gas emissions.

The Company's Compensation Committee set specific target levels for methane intensity rates and total greenhouse gas emissions, and the performance goal is intended to incentivize and reward performance to the extent management achieves methane intensity and greenhouse gas reduction targets making progress towards or exceeding the Company's 2030 goals.

The number of these Emissions Performance Shares that will vest and be paid out will depend upon the number of methane intensity segment targets achieved and whether the Company meets the total greenhouse gas emissions target.

The fair value of these Emissions Performance Shares is calculated by multiplying the expected number of shares that will be issued by the average market price of Company common stock on the date of grant reduced by the present value of forgone dividends over the vesting term of the award.

The fair value is recorded as compensation expense over the vesting term of the award.

The performance goal related to the TSR Performance Shares over the three-year performance cycle is the Company’s three-year total shareholder return relative to the three-year total shareholder return of the other companies in the Report Group.

The performance shares granted during the quarter ended December 31, 2025 include awards that must meet a performance goal related to relative total shareholder return over a three-year performance cycle ("TSR Performance Shares").

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Compensation Committee ("Report Group").

Three-year total shareholder return for a given company will be based on the data reported for that company (with the starting and ending stock prices over the performance cycle calculated as the average closing stock price for the prior calendar month and with dividends reinvested in that company’s securities at each ex-dividend date) in the Bloomberg database.

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This price is multiplied by the number of TSR Performance Shares awarded, the result of which is recorded as compensation expense over the vesting term of the award.

The Company granted 132,352 restricted stock units during the nine months ended June 30, 2025.

The weighted average fair value of such restricted stock units was $ 58.64 per share for the nine months ended June 30, 2025.

Restricted stock

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units represent the right to receive shares of common stock of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company) at the end of a specified time period.

The Company granted 128,755 restricted stock units during the quarter ended December 31, 2025.

The weighted average fair value of such restricted stock units was $ 77.75 per share for the quarter ended December 31, 2025.

Restricted stock units represent the right to receive shares of common stock of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company) at the end of a specified time period.

These restricted stock units do not entitle the participant to receive dividends during the vesting period.

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The fair value of restricted stock units on the date of award is recorded as compensation expense over the vesting period.

Note 2 – Revenue from Contracts with Customers

The following tables provide a disaggregation of the Company's revenues for the quarter and nine months ended June 30, 2025 and 2024, presented by type of service from each reportable segment.

Quarter Ended June 30, 2025 (Thousands)

Revenues By Type of Service Exploration and Production Pipeline and Storage Gathering Utility All Other Corporate and Intersegment Eliminations Total Consolidated

Production of Natural Gas $ 300,137 $ — $ — $ — $ — $ — $ 300,137

Production of Crude Oil 434 — — — — — 434

Natural Gas Processing 267 — — — — — 267

Natural Gas Gathering Service — — 67,873 — — ( 65,354 ) 2,519

Natural Gas Transportation Service — 80,235 — 21,639 — ( 26,845 ) 75,029

Natural Gas Storage Service — 25,028 — — — ( 10,604 ) 14,424

Natural Gas Residential Sales — — — 118,551 — — 118,551

Natural Gas Commercial Sales — — — 15,349 — — 15,349

Natural Gas Industrial Sales — — — 732 — ( 1 ) 731

Other 530 316 — ( 633 ) — ( 224 ) ( 11 )

Total Revenues from Contracts with Customers 301,368 105,579 67,873 155,638 — ( 103,028 ) 527,430

Alternative Revenue Programs — — — 1,885 — — 1,885

Derivative Financial Instruments 2,515 — — — — — 2,515

Total Revenues $ 303,883 $ 105,579 $ 67,873 $ 157,523 $ — $ ( 103,028 ) $ 531,830

Note 2 – Pending Acquisition

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

(the “Seller”), pursuant to which, among other things, the Company agreed to acquire from the Seller all of the issued and outstanding equity interests of Vectren Energy Delivery of Ohio, LLC (“CenterPoint Ohio”) for an aggregate purchase price of $ 2.62 billion, subject to customary adjustments, as provided in the Purchase Agreement.

This acquisition will add significant regulated scale for the Company, doubling the size of the Company’s gas utility rate base, while expanding its operations beyond New York and Pennsylvania into the neighboring state of Ohio, a state with a constructive regulatory and political environment that is supportive of natural gas.

Closing is expected to occur 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.

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.

After deducting placement fees, the net proceeds to the Company amounted to $ 338.6 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 Toronto-Dominion Bank (“TD Bank”), New York Branch and Wells Fargo Bank, National Association (together with TD Bank, 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.

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Nine Months Ended June 30, 2025 (Thousands)

Revenues By Type of Service Exploration and Production Pipeline and Storage Gathering Utility All Other Corporate and Intersegment Eliminations Total Consolidated

Note 3 – Revenue from Contracts with Customers

The following tables provide a disaggregation of the Company's revenues for the three months ended December 31, 2025 and 2024, presented by type of service from each reportable segment.

As reported in the Company's 2025 Form 10-K, the segment reporting structure was modified to merge the Exploration and Production segment and Gathering segment into one reportable segment called Integrated Upstream and Gathering.

Prior year disaggregation of revenue information shown below has been restated to reflect this change in presentation.

Quarter Ended December 31, 2025 (Thousands)

Revenues By Type of Service Integrated Upstream and Gathering Pipeline and Storage Utility Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated

Production of Natural Gas $ 302,460 $ — $ — $ 302,460 $ — $ — $ 302,460

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Total Revenues $ 323,223 $ 106,901 $ 259,137 $ 689,261 $ — $ ( 37,754 ) $ 651,507

Quarter Ended June 30, 2024 (Thousands)

Revenues By Type of Service Exploration and Production Pipeline and Storage Gathering Utility All Other Corporate and Intersegment Eliminations Total Consolidated

Quarter Ended December 31, 2024 (Thousands)

Revenues By Type of Service Integrated Upstream and Gathering Pipeline and Storage Utility Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated

Production of Natural Gas $ 217,458 $ — $ — $ 217,458 $ — $ — $ 217,458

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Nine Months Ended June 30, 2024 (Thousands)

Revenues By Type of Service Exploration and Production Pipeline and Storage Gathering Utility All Other Corporate and Intersegment Eliminations Total Consolidated

Production of Natural Gas $ 580,233 $ — $ — $ — $ — $ — $ 580,233

Production of Crude Oil 1,722 — — — — — 1,722

Natural Gas Processing 765 — — — — — 765

Natural Gas Gathering Service — — 186,701 — — ( 174,544 ) 12,157

Natural Gas Transportation Service — 232,532 — 88,817 — ( 73,040 ) 248,309

Natural Gas Storage Service — 71,247 — — — ( 30,520 ) 40,727

Natural Gas Residential Sales — — — 445,971 — — 445,971

Natural Gas Commercial Sales — — — 62,117 — — 62,117

Natural Gas Industrial Sales — — — 2,668 — ( 5 ) 2,663

Other 1,416 4,073 — ( 2,066 ) — ( 695 ) 2,728

Total Revenues from Contracts with Customers 584,136 307,852 186,701 597,507 — ( 278,804 ) 1,397,392

Alternative Revenue Programs — — — 19,949 — — 19,949

Derivative Financial Instruments 155,401 — — — — — 155,401

Total Revenues $ 739,537 $ 307,852 $ 186,701 $ 617,456 $ — $ ( 278,804 ) $ 1,572,742

The Company records revenue related to its derivative financial instruments in the Exploration and Production segment.

The Company records revenue related to its derivative financial instruments in the Integrated Upstream and Gathering segment.

The Company also records revenue related to alternative revenue programs in its Utility segment.

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The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

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The following table sets forth, by level within the fair value hierarchy, the Company's financial assets and liabilities (as applicable) that were accounted for at fair value on a recurring basis as of June 30, 2025 and September 30, 2024.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

Recurring Fair Value Measures At fair value as of June 30, 2025

Recurring Fair Value Measures At fair value as of December 31, 2025

(Thousands of Dollars) Level 1 Level 2 Level 3 Netting

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Over the Counter No Cost Collars – Gas — 26,413 — ( 8,154 ) 18,259

Contingent Consideration for Asset Sale — — — — —

Foreign Currency Contracts — 184 — ( 439 ) ( 255 )

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Total Net Assets/(Liabilities) $ 285,287 $ 69,209 $ — $ — $ 354,496

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Recurring Fair Value Measures At fair value as of September 30, 2025

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Over the Counter No Cost Collars – Gas — 24,149 — ( 12,805 ) 11,344

Contingent Consideration for Asset Sale — 729 — — 729

Foreign Currency Contracts — 144 — ( 675 ) ( 531 )

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The net asset or net liability for each counterparty is recorded as an asset or liability on the Company’s balance sheet.

The following table presents impairments of assets associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy as of June 30, 2025 and 2024 (in thousands):

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Nonrecurring Fair Value Measures Nine Months Ended June 30,

The following table presents impairments of assets associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy as of December 31, 2025 and 2024 (in thousands):

Nonrecurring Fair Value Measures Quarter Ended December 31,

Segment Date of Measurement Fair Value 2025 2024

Impairment of Assets:

Water Disposal Assets Exploration and Production December 31, 2024 $ 12,880 $ 33,453 $ —

Water Disposal Assets Integrated Upstream and Gathering December 31, 2024 $ 12,880 $ — $ 33,453

In exploring the potential sale of certain water disposal assets during the quarter ended December 31, 2024, the Company determined that the fair market value of such assets was less than the recorded net book value resulting in an impairment charge that reduced the net book value to fair market value.

These assets are used to dispose of water from operations in the Exploration and Production segment.

These assets are used to dispose of water from operations in the Integrated Upstream and Gathering segment.

Derivative Financial Instruments

The derivative financial instruments reported in Level 2 at June 30, 2025 and September 30, 2024 include natural gas price swap agreements, natural gas no cost collars, and foreign currency contracts, all of which are used in the Company’s Exploration and Production segment.

The derivative financial instruments reported in Level 2 at December 31, 2025 and September 30, 2025 include natural gas price swap agreements, natural gas no cost collars, and foreign currency contracts, all of which are used in the Company’s Integrated Upstream and Gathering segment.

The fair value of the Level 2 price swap agreements and no cost collars is based on an internal cash flow model that uses observable inputs (i.e.

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

At June 30, 2025, the Company determined that nonperformance risk associated with the price swap agreements, no cost collars and foreign currency contracts would have no material impact on its financial position or results of operation.

At December 31, 2025, the Company determined that nonperformance risk associated with the price swap agreements, no cost collars and foreign currency contracts would have no material impact on its financial position or results of operation.

To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates.

Derivative financial instruments reported in Level 2 at June 30, 2025 also includes the contingent consideration associated with the sale of the Exploration and Production segment's California assets on June 30, 2022.

The terms of the purchase and sale agreement specified that the Company could receive up to three annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed $ 10 million per year, with the amount of each annual payment calculated at $ 1.0 million for each $ 1 per barrel that the ICE Brent Average for each calendar year exceeds $ 95 per barrel up to $ 105 per barrel.

The calendar 2023 and 2024 contingency periods expired with the ICE Brent Average falling below $ 95 per barrel each calendar year.

The fair value of the contingent consideration was calculated using a Monte Carlo simulation model that uses observable inputs, including the ICE Brent closing price as of the valuation date, initial and max trigger price, volatility, risk-free rate, time of maturity and counterparty risk.

The fair value of this contingent consideration is estimated to be zero as of June 30, 2025.

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Note 5 – Financial Instruments

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Based on these criteria, the fair market value of long-term debt, including current portion, was as follows (in thousands):

June 30, 2025 September 30, 2024

December 31, 2025 September 30, 2025

Amount Fair Value Carrying

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As such, the Company considers the debt to be Level 2.

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Other Financial Instruments.

Any temporary cash investments, notes payable to banks and commercial paper are stated at cost.

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The components of the Company's Other Investments are as follows (in thousands):

At June 30, 2025 At September 30, 2024

At December 31, 2025 At September 30, 2025

Life Insurance Contracts $ 44,576 $ 44,478

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Derivative Financial Instruments.

The Company uses derivative financial instruments to manage commodity price risk in the Exploration and Production segment.

The Company uses derivative financial instruments to manage commodity price risk in the Integrated Upstream and Gathering segment.

The Company enters into over-the-counter no cost collar and swap agreements for natural gas to manage the price risk associated with forecasted sales of natural gas.

In addition, the Company also enters into foreign exchange forward contracts to manage the risk of currency fluctuations associated with transportation costs denominated in Canadian currency in the Exploration and Production segment.

These instruments are accounted for as cash flow hedges.

The duration of the Company’s cash flow hedges does not typically exceed 5 years while the foreign currency forward contracts do not exceed 6 years.

On June 30, 2022, the Company completed the sale of Seneca’s California assets.

The terms of the purchase and sale agreement specified that the Company could receive up to three annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed $ 10 million per year, with the amount of each annual payment calculated as $ 1.0 million for each $ 1 per barrel that the ICE Brent Average for each calendar year exceeds $ 95 per barrel up to $ 105 per barrel.

The calendar 2023 and 2024 contingency periods expired with the ICE Brent Average falling below $ 95 per barrel each calendar year.

The Company has determined that this contingent consideration meets the definition of a derivative under the authoritative accounting guidance.

Changes in the fair value of this contingent consideration are marked-to-market each reporting period, with changes in fair value recognized in Other Income (Deductions) on the Consolidated Statement of Income.

The fair value of this contingent consideration was estimated to be zero and $ 0.7 million at June 30, 2025 and September 30, 2024, respectively.

A $ 0.7 million mark-to-market adjustment to reduce the fair value of the contingent consideration was recorded during the nine months ended June 30, 2025.

The Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at June 30, 2025 and September 30, 2024.

The duration of the Company’s cash flow hedges and foreign currency forward contracts do not typically exceed 5 years.

The Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at December 31, 2025 and September 30, 2025.

Cash Flow Hedges

For derivative financial instruments that are designated and qualify as a cash flow hedge, the gain or loss on the derivative is reported as a component of other comprehensive income (loss) and reclassified into earnings in the period or periods during which the hedged transaction affects earnings.

As of June 30, 2025, the Company had 427.0 Bcf of natural gas commodity derivative contracts (swaps and no cost collars) outstanding.

As of June 30, 2025, the Company was hedging a total of $ 47.2 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts.

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As of June 30, 2025, the Company had $ 44.5 million of net hedging losses after taxes included in the accumulated other comprehensive income (loss) balance.

Of this amount, it is expected that $ 15.7 million of unrealized losses after taxes will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged transactions are recorded in earnings.

As of December 31, 2025, the Company had 403.1 Bcf of natural gas commodity derivative contracts (swaps and no cost collars) outstanding.

As of December 31, 2025, the Company was hedging a total of $ 41.0 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts.

As of December 31, 2025, the Company had $ 46.2 million of net hedging gains after taxes included in the accumulated other comprehensive income (loss) balance.

Of this amount, it is expected that $ 45.9 million of unrealized gains after taxes will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged transactions are recorded in earnings.

The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the

Three Months Ended June 30, 2025 and 2024 (Thousands of Dollars)

Three Months Ended December 31, 2025 and 2024 (Thousands of Dollars)

Derivatives in Cash Flow Hedging Relationships Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on

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Three Months Ended

June 30, Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income for the

December 31, Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income for the

Three Months Ended

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Total $ 49,098 $ ( 53,516 ) $ 13,274 $ 29,504

The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the

Nine Months Ended June 30, 2025 and 2024 (Thousands of Dollars)

Derivatives in Cash Flow Hedging Relationships Amount of Derivative Gain or

(Loss) Recognized in Other

Comprehensive Income (Loss) on

the Consolidated Statement of

Comprehensive Income (Loss)

Nine Months Ended

(Loss) Reclassified from

Accumulated Other

Comprehensive Income (Loss) on

the Consolidated Balance Sheet

into the Consolidated Statement of

Income for the

Nine Months Ended

2025 2024 2025 2024

Commodity Contracts $ ( 113,145 ) $ 238,184 Operating Revenue $ 24,409 $ 155,401

Foreign Currency Contracts ( 530 ) 211 Operating Revenue ( 808 ) ( 198 )

Total $ ( 113,675 ) $ 238,395 $ 23,601 $ 155,203

The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position.

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The majority of the Company’s counterparties are financial institutions and energy traders.

The Company has over-the-counter swap positions, no cost collars and applicable foreign currency forward contracts with eighteen counterparties of which three are in a net gain position.

On average, the Company had $ 0.8 million of credit exposure per counterparty in a gain position at June 30, 2025.

The maximum credit exposure per counterparty in a gain position at June 30, 2025 was $ 2.0 million.

As of June 30, 2025, no collateral was received from the counterparties by the Company.

The Company has over-the-counter swap positions, no cost collars and applicable foreign currency forward contracts with seventeen counterparties of which sixteen are in a net gain position.

On average, the Company had $ 4.3 million of credit exposure per counterparty in a gain position at December 31, 2025.

The maximum credit exposure per counterparty in a gain position at December 31, 2025 was $ 10.8 million.

As of December 31, 2025, no collateral was received from the counterparties by the Company.

The Company's gain position on such derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral, nor had the counterparties' credit ratings declined to levels at which the counterparties were required to post collateral.

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In the event the Company’s credit rating increases or falls below a certain threshold (applicable debt ratings), the available credit that could be extended to the Company when it is in a derivative financial liability position would either increase or decrease.

A decline in the Company’s credit rating, in and of itself, would not cause the Company to be

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required to post or increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments).

A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to post or increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments).

If the Company’s outstanding derivative instrument contracts with a credit-risk contingency feature were in a liability position (or if the liability were larger) and/or the Company’s credit rating declined, then hedging collateral deposits or an increase to such deposits could be required.

At June 30, 2025, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $ 34.3 million according to the Company's internal model (discussed in Note 3 – Fair Value Measurements), and no hedging collateral deposits were required to be posted by the Company at June 30, 2025.

At December 31, 2025, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $ 0.2 million according to the Company's internal model (discussed in Note 4 – Fair Value Measurements), and no hedging collateral deposits were required to be posted by the Company at December 31, 2025.

Depending on the movement of commodity prices in the future, it is possible that these liability positions could swing into asset positions, at which point the Company would be exposed to credit risk on its derivative financial instruments.

In that case, the Company's counterparties could be required to post hedging collateral deposits.

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The Company’s requirement to post hedging collateral deposits and the Company's right to receive hedging collateral deposits is based on the fair value determined by the Company’s counterparties, which may differ from the Company’s assessment of fair value.

Note 6 – Income Taxes

The effective tax rates for the quarters ended June 30, 2025 and June 30, 2024 were 25.4 % and 34.3 %, respectively.

The decrease in the quarterly effective income tax rate was primarily driven by the impact of the impairment of exploration and production properties under the ceiling test recorded during the quarter ended June 30, 2024, which resulted in a larger income tax benefit on a loss before income taxes during the quarter ended June 30, 2024.

The effective tax rates for the nine months ended June 30, 2025 and June 30, 2024 were 24.5 % and 22.2 %, respectively.

The change in the year-to-date effective income tax rate was primarily driven by the impact of the impairments recorded in the quarters ended December 31, 2024 and June 30, 2024.

The impairments were related to exploration and production properties under the ceiling test in both nine-month periods and an impairment of certain water disposal assets recorded in the quarter ended December 31, 2024.

The impact of the impairments resulted in a smaller income tax expense on income before income taxes during each of the nine-month periods ended June 30, 2025 and June 30, 2024.

On July 4, 2025, the One Big Beautiful Bill Act (“OBBBA”) was signed into law.

The OBBBA makes permanent key elements of the Tax Cuts and Jobs Act, including 100% bonus depreciation, domestic research cost expensing, and the business interest expense limitation.

Additionally, the OBBBA incorporates the immediate deduction of intangible drilling costs for taxpayers subject to the Corporate Alternative Minimum Tax.

The Company is still evaluating the OBBBA and the results of such evaluations, which are not expected to have a material effect, are expected to be reflected on the Company’s Form 10-K for the year ended September 30, 2025.

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The effective tax rates for the quarters ended December 31, 2025 and December 31, 2024 were 24.6 % and 19.9 %, respectively.

The increase in the quarterly effective income tax rate was primarily driven by the impact of the impairments of exploration and production properties under the ceiling test and other operational assets recorded during the quarter ended December 31, 2024, which resulted in a smaller income tax expense on income before income taxes during the quarter ended December 31, 2024.

Note 7 – Capitalization

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Shares Amount

(Thousands, except per share amounts)

Balance at April 1, 2025 90,398 $ 90,398 $ 1,042,822 $ 1,855,366 $ ( 222,975 )

Net Income Available for Common Stock 149,818

Dividends Declared on Common Stock ($ 0.535 Per Share)

Other Comprehensive Income, Net of Tax 107,168

Share-Based Payment Expense (1)

Common Stock Issued Under Stock and Benefit Plans 12 12 529

Share Repurchases Under Repurchase Plan ( 54 ) ( 54 ) ( 630 ) ( 3,311 )

Balance at June 30, 2025 90,356 $ 90,356 $ 1,047,406 $ 1,953,533 $ ( 115,807 )

Balance at October 1, 2025 90,379 $ 90,379 $ 1,050,918 $ 2,012,529 $ ( 59,222 )

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Dividends Declared on Common Stock ($ 0.535 Per Share)

Other Comprehensive Loss, Net of Tax ( 100,331 )

Other Comprehensive Income, Net of Tax 26,232

Share-Based Payment Expense (1)

Common Stock Issued from Sale of Common Stock 4,403 4,403 334,173

Common Stock Issued (Repurchased) Under Stock and Benefit Plans 235 235 ( 5,925 )

Share Repurchases Under Repurchase Plan ( 829 ) ( 829 ) ( 9,615 ) ( 43,389 )

Balance at June 30, 2025 90,356 $ 90,356 $ 1,047,406 $ 1,953,533 $ ( 115,807 )

Balance at April 1, 2024 92,032 $ 92,032 $ 1,045,929 $ 2,090,172 $ 75,340

Net Loss Available for Common Stock ( 54,158 )

Dividends Declared on Common Stock ($ 0.515 Per Share)

Other Comprehensive Loss, Net of Tax ( 70,290 )

Share-Based Payment Expense (1)

Common Stock Issued Under Stock and Benefit Plans 11 11 587

Share Repurchases Under Repurchase Plan ( 431 ) $ ( 431 ) $ ( 4,942 ) $ ( 18,435 )

Balance at June 30, 2024 91,612 $ 91,612 $ 1,046,479 $ 1,970,384 $ 5,050

Balance at December 31, 2025 95,017 $ 95,017 $ 1,382,593 $ 2,143,340 $ ( 32,990 )

Balance at October 1, 2024 91,006 $ 91,006 $ 1,045,487 $ 1,727,326 $ ( 15,476 )

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Dividends Declared on Common Stock ($ 0.515 Per Share)

Other Comprehensive Income, Net of Tax 60,110

Other Comprehensive Loss, Net of Tax ( 60,677 )

Share-Based Payment Expense (1)

Common Stock Issued (Repurchased) Under Stock and Benefit Plans 156 156 ( 3,511 )

320 320 ( 2,514 )

Share Repurchases Under Repurchase Plan ( 549 ) $ ( 549 ) $ ( 6,361 ) $ ( 26,993 )

Balance at June 30, 2024 91,612 $ 91,612 $ 1,046,479 $ 1,970,384 $ 5,050

Balance at December 31, 2024 90,613 $ 90,613 $ 1,039,705 $ 1,698,648 $ ( 76,153 )

(1) Paid in Capital includes compensation costs associated with performance shares and/or restricted stock awards.

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Common Stock.

Common stock share activity during the nine months ended June 30, 2025 consisted of the following items:

Nine Months Ended June 30, 2025

Common stock share activity during the three months ended December 31, 2025 consisted of the following items:

Three Months Ended December 31, 2025

Vesting of Restricted Stock Units 138,643

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Common Stock Issued Under Stock and Benefit Plans 235,830

Share Repurchases Under Repurchase Plan ( 828,720 )

Total Net Shares Repurchased During the Nine Months Ended June 30, 2025 ( 650,037 )

Common Stock Issued from Sale of Common Stock 4,402,513

Total Common Stock Issued During the Three Months Ended December 31, 2025 4,638,343

(1) The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law.

On March 8, 2024, the Company’s Board of Directors authorized the Company to implement a share repurchase program, whereby the Company may repurchase outstanding shares of common stock, up to an aggregate amount of $ 200 million in the open market or through privately negotiated transactions, including through the use of trading plans intended to qualify under SEC Rule 10b5-1, in accordance with applicable securities laws and other restrictions.

In April 2025, repurchases under the program were temporarily paused.

As a result, the Company expects completion of the program will extend into calendar 2026.

The timing and amount of future repurchases under this program will depend on a number of factors, including but not limited to stock price, market conditions, applicable securities laws (including SEC Rule 10b-18), corporate and regulatory requirements, and capital and liquidity needs.

During the nine months ended June 30, 2025, the Company executed transactions to repurchase 828,720 shares at an average price of $ 64.37 per share, for a total cost of $ 53.8 million (including broker fees and excise taxes).

Share repurchases that settled during the nine months ended June 30, 2025 were funded with cash provided by operating activities and/or short-term borrowings.

In the future, it is expected that this share repurchase program will continue to be funded with cash provided by operating activities and/or through the use of short-term borrowings.

The program has no fixed expiration date.

Short-Term Borrowings.

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.

On December 17, 2025, the Company completed the issuance and sale, in a private placement, of 4,402,513 shares of the Company's common stock, par value $ 1.00 per share, at a price of $ 79.50 per share.

After deducting placement fees, the net proceeds to the Company amounted to $ 338.6 million.

The proceeds of this issuance were used for general corporate purposes, including to fund a portion of the purchase price of the Company's previously announced acquisition of CenterPoint Energy Resources Corp.'s Ohio regulated gas utility business.

Refer to Note 2 – Pending Acquisition for further discussion.

Current Portion of Long-Term Debt.

The Current Portion of Long-Term Debt at June 30, 2025 consisted of a $ 300.0 million long-term delayed draw term loan that matures in February 2026.

The Current Portion of Long-Term Debt at September 30, 2024 consisted of $ 50.0 million of 7.38 % notes that matured in June 2025 and $ 450.0 million of 5.20 % notes with a maturity date in July 2025.

As discussed below, the Company redeemed the $ 450.0 million of 5.20 % notes on March 6, 2025.

Long-Term Debt.

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.

In the Exploration and Production and Gathering segments, the call premiums of $ 0.6 million for the redemption of the 5.20 % notes and $ 1.8 million for the

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redemption of the 5.50 % notes, were recorded to Interest Expense on Long-Term Debt on the Consolidated Income Statement during the quarter ended March 31, 2025, and in the Pipeline and Storage segment, the call premiums of $ 0.2 million for the 5.20 % notes redeemed and $ 1.5 million for the 5.50 % notes redeemed were recorded to Unamortized Debt Expense on the Consolidated Balance Sheet as of March 31, 2025.

The remaining proceeds of the debt issuances were used to repay a portion of short-term borrowings the Company incurred to fund a trust for the benefit of holders of $ 50.0 million of 7.38 % notes under the Company's 1974 indenture prior to the June 13, 2025 maturity date of these notes.

Placing these funds in trust enabled the Company to cancel and discharge the 1974 indenture.

This relieved the Company from its obligations to comply with the 1974 indenture's covenants.

The funds were paid out of the trust on June 13, 2025 for the redemption of the $ 50.0 million of 7.38 % notes, leaving no notes outstanding under the 1974 indenture.

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.

Delayed Draw Term Loan.

On February 14, 2024, the Company entered into a Term Loan Agreement (the “Term Loan Agreement”) with six lenders, all of which are lenders under the Credit Agreement.

The Term Loan Agreement provides a $ 300.0 million unsecured committed delayed draw term loan facility with a maturity date of February 14, 2026, and the Company has the ability to select interest periods of one, three or six months for borrowings.

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

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.

The Company used the proceeds for general corporate purposes, which included the redemption of outstanding commercial paper.

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

The current weighted average locked-in interest rate is 5.82 % until mid-August 2025 .

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 %.

Note 8 – Commitments and Contingencies

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It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs.

At June 30, 2025, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $ 3.7 million.

The Company's liability for such clean-up costs has been recorded in Other Liabilities on the Consolidated Balance Sheet at June 30, 2025.

The Company has a regulatory liability of $ 2.1 million related to environmental clean-up costs at June 30, 2025 and is currently not aware of any material additional exposure to environmental liabilities.

At December 31, 2025, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $ 2.9 million.

The Company's liability for such clean-up costs has been recorded in Other Liabilities on the Consolidated Balance Sheet at December 31, 2025.

The Company has a regulatory liability of $ 1.5 million related to environmental clean-up costs at December 31, 2025 and is currently not aware of any material additional exposure to environmental liabilities.

However, changes in environmental laws and regulations, new information or other factors could have an adverse financial impact on the Company.

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These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things.

While these other matters arising in the normal course of business could have a material effect on earnings and cash flows in the period in which they are resolved, an estimate of the possible loss or range of loss, if any, cannot be made at this time.

While these other matters arising in the normal

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course of business could have a material effect on earnings and cash flows in the period in which they are resolved, an estimate of the possible loss or range of loss, if any, cannot be made at this time.

Note 9 – Business Segment Information

The Company reports financial results for four segments:

Exploration and Production, Pipeline and Storage, Gathering and Utility.

The division of the Company’s operations into reportable segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors.

The data presented in the tables below reflect financial information for the segments and reconcile to consolidated amounts.

The Company reports financial results for three segments:

Integrated Upstream and Gathering, Pipeline and Storage, and Utility.

The division of the Company’s operations into reportable segments is based on a combination of factors including differences in products and services as well as regulatory environments.

Prior year segment information shown below has been recast to reflect this change in presentation.

The Company's Chief Executive Officer, its Chief Operating Decision Maker (CODM), evaluates segment performance primarily using earnings attributable to the Company.

External reporting is consistent with the internal financial reports used by the CODM to regularly assess performance of the business, make operating decisions and allocate resources.

The Integrated Upstream and Gathering segment is composed of the operations of Seneca and Midstream Company.

Seneca is engaged in the exploration for and development of natural gas reserves in the Appalachian region of the United States.

Midstream Company builds, owns and operates natural gas processing and pipeline gathering facilities in the Appalachian region, primarily providing gathering services to Seneca.

The Pipeline and Storage segment operations are regulated by the FERC for both Supply Corporation and Empire.

Supply Corporation transports and stores natural gas for utilities (including Distribution Corporation), natural gas marketers, exploration and production companies (including Seneca) and pipeline companies serving northeastern United States markets.

Empire transports and stores natural gas for major industrial companies, utilities (including Distribution Corporation) and power producers in New York State.

Empire also transports natural gas for utilities (including Distribution Corporation), natural gas marketers and exploration and production companies (including Seneca) from producing areas in Pennsylvania to markets in New York and to interstate pipeline delivery points with access to additional markets in the northeastern United States and Canada.

The Utility segment operations are regulated by the NYPSC and the PaPUC and are carried out by Distribution Corporation.

Distribution Corporation sells natural gas to retail customers and provides natural gas transportation services in western New York and northwestern Pennsylvania.

The data presented in the tables below reflects financial information for the segments and reconciles to consolidated amounts.

As stated in the 2025 Form 10-K, the Company evaluates segment performance based on income before discontinued operations, when applicable.

When this is not applicable, the Company evaluates performance based on net income.

There have not been any changes in the basis of segmentation nor in the basis of measuring segment profit or loss from those used in the Company’s 2024 Form 10-K.

A listing of segment assets at June 30, 2025 and September 30, 2024 is shown in the tables below.

If discontinued operations are not applicable, the Company evaluates performance based on net income.

There have been no changes in the basis of segmentation or in the basis of measuring segment profit or loss from those used in the Company’s 2025 Form 10-K.

A listing of segment assets at December 31, 2025 and December 31, 2024 is shown in the tables below.

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Quarter Ended June 30, 2025 (Thousands)

Exploration and Production Pipeline and Storage Gathering Utility Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated

Three Months Ended December 31, 2025

Integrated Upstream and Gathering Pipeline

Storage Utility Total

Eliminations (4)

Revenue from External Customers (1)

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Intersegment Revenues

Segment Profit:

Net Income (Loss)

— 37,664 90 37,754 — ( 37,754 ) —

Nine Months Ended June 30, 2025 (Thousands)

Exploration and Production Pipeline and Storage Gathering Utility Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated

Revenue from External Customers

Total Revenues 323,223 106,901 259,137 689,261 — ( 37,754 ) 651,507

Operation and Maintenance Expense (2) :

Upstream General and Administrative Expense 19,406 — — 19,406 — ( 63 ) 19,343

Lease Operating Expense 16,826 — — 16,826 — ( 789 ) 16,037

Gathering Operation and Maintenance Expense 10,388 — — 10,388 — ( 69 ) 10,319

All Other Operation and Maintenance Expense 3,378 27,263 60,997 91,638 — 5,652 97,290

Purchased Gas Expense (2)

— — 122,285 122,285 — ( 36,679 ) 85,606

Intersegment Revenues $ — $ 113,849 $ 184,834 $ 279 $ 298,962 $ — $( 298,962 ) $ —

Depreciation, Depletion and Amortization Expense (2)

84,263 19,102 18,479 121,844 — 181 122,025

Impairment of Assets (Significant Non-Cash Item) (2)

— — — — — — —

Interest Expense (2)

16,133 11,801 11,606 39,540 136 3,698 43,374

Interest Income ( 193 ) ( 964 ) ( 1,039 ) ( 2,196 ) ( 10 ) ( 571 ) ( 2,777 )

Income Tax Expense (Benefit) (2)

44,111 10,366 7,335 61,812 ( 37 ) ( 2,438 ) 59,337

Other Expense (Income) Items (3)

4,864 8,114 5,384 18,362 33 913 19,308

Segment Profit:

Net Income (Loss)

(Thousands) Exploration and Production Pipeline and Storage Gathering Utility Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated

$ 124,047 $ 31,219 $ 34,090 $ 189,356 $ ( 122 ) $ ( 7,589 ) $ 181,645

Expenditures for Additions to Long-Lived Assets

$ 141,849 $ 37,602 $ 43,094 $ 222,545 $ — $ 176 $ 222,721

Integrated Upstream and Gathering Pipeline

Storage Utility Total

Eliminations (4)

Segment Assets:

At June 30, 2025 $ 2,574,771 $ 2,421,610 $ 1,024,345 $ 2,507,973 $ 8,528,699 $ 8,216 $( 90,755 ) $ 8,446,160

At December 31, 2025 $ 3,925,191 $ 2,504,541 $ 2,645,957 $ 9,075,689 $ 8,565 $ 121,618 $ 9,205,872

At September 30, 2025 $ 3,701,646 $ 2,412,747 $ 2,534,289 $ 8,648,682 $ 8,704 $ 61,718 $ 8,719,104

Quarter Ended June 30, 2024 (Thousands)

Exploration and Production Pipeline and Storage Gathering Utility Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated

Three Months Ended December 31, 2024

Integrated Upstream and Gathering Pipeline

Storage Utility Total

Corporate and

Eliminations (4)

Revenue from External Customers (1)

1 unchanged sentence

Intersegment Revenues

Segment Profit:

Net Income (Loss) $( 112,028 ) $ 30,690 $ 24,979 $ 2,559 $( 53,800 ) $( 124 ) $( 234 ) $( 54,158 )

Nine Months Ended June 30, 2024 (Thousands)

Exploration and Production Pipeline and Storage Gathering Utility Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated

Revenue from External Customers

— 37,862 85 37,947 — ( 37,947 ) —

Intersegment Revenues $ — $ 103,781 $ 174,544 $ 479 $ 278,804 $ — $( 278,804 ) $ —

Total Revenues 252,308 106,612 228,509 587,429 — ( 37,947 ) 549,482

Operation and Maintenance Expense (2) :

Upstream General and Administrative Expense 19,326 — — 19,326 — ( 59 ) 19,267

Lease Operating Expense 10,651 — — 10,651 — ( 1,587 ) 9,064

Gathering Operation and Maintenance Expense 6,735 — — 6,735 — ( 65 ) 6,670

All Other Operation and Maintenance Expense 3,867 27,034 56,260 87,161 — 2,564 89,725

Purchased Gas Expense (2)

— — 101,473 101,473 — ( 36,136 ) 65,337

Depreciation, Depletion and Amortization Expense (2)

73,819 18,585 16,827 109,231 — 139 109,370

Impairment of Assets (Significant Non-Cash Item) (2)

141,802 — — 141,802 — — 141,802

Interest Expense (2)

19,410 11,729 10,716 41,855 116 ( 4,228 ) 37,743

Interest Income ( 679 ) ( 2,006 ) ( 648 ) ( 3,333 ) — 1,650 ( 1,683 )

Income Tax Expense (Benefit) (2)

( 6,451 ) 11,177 7,022 11,748 ( 59 ) ( 507 ) 11,182

Other Expense (Income) Items (3)

3,460 7,639 4,360 15,459 136 424 16,019

Segment Profit:

Net Income (Loss)

$ ( 19,632 ) $ 32,454 $ 32,499 $ 45,321 $ ( 193 ) $ ( 142 ) $ 44,986

Expenditures for Additions to Long-Lived Assets

$ 135,629 $ 19,792 $ 36,430 $ 191,851 $ — $ 204 $ 192,055

(1) All Revenue from External Customers originated in the United States.

(2) The Company considers this line to be a significant expense.

(3) Consists of Property, Franchise and Other Taxes, Non-Service Pension and Post-Retirement Benefits Costs (Credits), Other (Income) Deductions, and Purchased Gas Expense for the Pipeline and Storage Segment.

(4) Corporate and All Other categories primarily represent other non-segment business activities and eliminating entries.

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Retirement Plan Other Post-Retirement Benefits

Three Months Ended June 30, 2025 2024 2025 2024

Service Cost $ 1,023 $ 1,049 $ 130 $ 109

Interest Cost 9,223 10,890 3,625 3,890

Expected Return on Plan Assets ( 14,647 ) ( 17,086 ) ( 6,536 ) ( 6,660 )

Amortization of Prior Service Cost (Credit) 76 91 ( 107 ) ( 107 )

Amortization of (Gains) Losses 1,620 ( 335 ) 9 ( 567 )

Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)

85 4,057 ( 447 ) 2,248

Net Periodic Benefit Cost (Income) $ ( 2,620 ) $ ( 1,334 ) $ ( 3,326 ) $ ( 1,087 )

Retirement Plan Other Post-Retirement Benefits

Nine Months Ended June 30, 2025 2024 2025 2024

Three Months Ended December 31, 2025 2024 2025 2024

Service Cost $ 861 $ 1,023 $ 105 $ 130

9 unchanged sentences

Employer Contributions.

The Company did not make any contributions to its tax-qualified, noncontributory defined benefit retirement plan (Retirement Plan) during the nine months ended June 30, 2025, and does not anticipate making any such contributions during the remainder of fiscal 2025.

The Company also did not make any contributions to its VEBA trusts for its other post-retirement benefits during the nine months ended June 30, 2025, and does not anticipate making any such contributions during the remainder of fiscal 2025.

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.

Note 11 – Regulatory Matters

2 unchanged sentences

The 2024 Rate Order authorizes a three-year rate plan effective October 1, 2024, with a make-whole provision allowing full recovery of revenues that would have been billed at the new rates between October 1, 2024 and December 31, 2024.

It also reflects a return on equity of 9.7 % and authorizes a revenue requirement increase of $ 57.3 million in fiscal 2025, an additional revenue requirement increase of $ 15.8 million in fiscal 2026, and an additional revenue requirement increase of $ 12.7 million in fiscal 2027.

The revenue requirement for each year of the three-year plan has been reduced by $ 14 million for actuarial projections of income that is

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expected to be recognized for qualified pension and other post-retirement benefits.

It also reflects a return on equity of 9.7 % and authorized a revenue requirement increase of $ 57.3 million in fiscal 2025, an additional revenue requirement increase of $ 15.8 million in fiscal 2026, and an additional revenue requirement increase of $ 12.7 million in fiscal 2027.

These revenue requirement increases are being reflected in customer bills on a levelized basis over the three-year rate plan.

The revenue requirement for each year of the three-year plan has been reduced by $ 14 million for actuarial projections of income that is expected to be recognized for qualified pension and other post-retirement benefits.

Qualified pension and other post-retirement benefit income or costs are matched with amounts included in revenue resulting in zero impact to earnings.

4 unchanged sentences

The 2023 Rate Order provided for, among other things, an increase in Distribution Corporation’s annual base rate operating revenues of $ 23 million and authorized a new weather normalization adjustment mechanism.

On January 28, 2026, Distribution Corporation made a filing with the PaPUC seeking an increase in its annual base rate operating revenues of $ 19.7 million with a proposed effective date of March 29, 2026.

The Company is proposing, among other things, a new residential energy efficiency pilot program and to make

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permanent its weather normalization adjustment mechanism.

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

The filing will be suspended for seven months 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 quarters ended March 31, 2025 and June 30, 2025, Distribution Corporation recovered $ 0.2 million and $ 0.3 million, respectively, from customers.

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

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

FERC Jurisdiction

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

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.

2 unchanged sentences

This settlement amendment is estimated to decrease Empire's revenues on a yearly basis by approximately $ 0.5 million.

As well, the revenue sharing mechanism under the 2019 rate case settlement was adjusted and Empire committed to undertake greenhouse gas and reliability reporting.

Empire will not be able to file a new Section 4 rate case before April 30, 2027 and is required to file a Section 4 rate case by May 31, 2031.

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 1. Financial Statements