NATIONAL FUEL GAS CO 10-Q

Item 1. Financial Statements National Fuel Gas Company Consolidated Statements of Income and Earnings Reinvested in the Business (Unaudited) Three Months Ended March 31, Six Months Ended March 31, (Thousands of U.S. Dollars, Except Per Common Share Amounts) 2023 2022 2023 2022 INCOME Operating Revenues: Utility Revenues $ 406,758 $ 369,092 $ 718,376 $ 605,776 Exploration and Production and Other Revenues 244,552 261,676 521,525 505,957 Pipeline and Storage and Gathering Revenues 65,951 70,952 136,218 136,544 717,261 701,720 1,376,119 1,248,277 Operating Expenses: Purchased Gas 243,839 199,592 415,035 301,219 Operation and Maintenance: Utility 56,453 53,476 106,805 100,120 Exploration and Production and Other 31,782 49,806 58,655 95,425 Pipeline and Storage and Gathering 37,479 33,518 70,740 63,446 Property, Franchise and Other Taxes 25,367 27,717 51,572 52,219 Depreciation, Depletion and Amortization 100,964 91,245 197,564 179,823 495,884 455,354 900,371 792,252 Operating Income 221,377 246,366 475,748 456,025 Other Income (Expense): Other Income (Deductions) 2,884 10,018 9,203 8,940 Interest Expense on Long-Term Debt ( 27,583 ) ( 30,079 ) ( 57,188 ) ( 60,209 ) Other Interest Expense ( 5,861 ) ( 1,519 ) ( 9,704 ) ( 2,680 ) Income Before Income Taxes 190,817 224,786 418,059 402,076 Income Tax Expense 49,937 57,458 107,489 102,356 Net Income Available for Common Stock 140,880 167,328 310,570 299,720 EARNINGS REINVESTED IN THE BUSINESS Balance at Beginning of Period 1,713,176 1,281,963 1,587,085 1,191,175 1,854,056 1,449,291 1,897,655 1,490,895 Dividends on Common Stock ( 43,602 ) ( 41,608 ) ( 87,201 ) ( 83,212 ) Balance at March 31 $ 1,810,454 $ 1,407,683 $ 1,810,454 $ 1,407,683 Earnings Per Common Share: Basic: Net Income Available for Common Stock $ 1.53 $ 1.83 $ 3.39 $ 3.28 Diluted: Net Income Available for Common Stock $ 1.53 $ 1.82 $ 3.37 $ 3.26 Weighted Average Common Shares Outstanding: Used in Basic Calculation 91,794,765 91,444,638 91,686,110 91,354,488 Used in Diluted Calculation 92,256,348 92,064,711 92,264,717 92,047,467 Dividends Per Common Share: Dividends Declared $ 0.475 $ 0.455 $ 0.950 $ 0.910 See Notes to Condensed Consolidated Financial Statements 6 Table of Contents National Fuel Gas Company Consolidated Statements of Comprehensive Income (Unaudited) Three Months Ended March 31, Six Months Ended March 31, (Thousands of U.S. Dollars) 2023 2022 2023 2022 Net Income Available for Common Stock $ 140,880 $ 167,328 $ 310,570 $ 299,720 Other Comprehensive Income (Loss), Before Tax: Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period 310,544 ( 641,606 ) 608,137 ( 478,474 ) Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income 18,940 130,221 178,281 292,809 Other Post-Retirement Adjustment for Regulatory Proceeding — ( 7,351 ) — ( 7,351 ) Other Comprehensive Income (Loss), Before Tax 329,484 ( 518,736 ) 786,418 ( 193,016 ) Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period 85,394 ( 175,605 ) 166,770 ( 130,956 ) Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income 5,208 35,641 48,779 80,141 Income Tax Expense (Benefit) Related to Other Post-Retirement Adjustment for Regulatory Proceeding — ( 1,544 ) — ( 1,544 ) Income Taxes – Net 90,602 ( 141,508 ) 215,549 ( 52,359 ) Other Comprehensive Income (Loss) 238,882 ( 377,228 ) 570,869 ( 140,657 ) Comprehensive Income (Loss) $ 379,762 $ ( 209,900 ) $ 881,439 $ 159,063 See Notes to Condensed Consolidated Financial Statements 7 Table of Contents National Fuel Gas Company Consolidated Balance Sheets (Unaudited) March 31, 2023 September 30, 2022 (Thousands of U.S. Dollars) ASSETS Property, Plant and Equipment $ 12,978,137 $ 12,551,909 Less - Accumulated Depreciation, Depletion and Amortization 6,162,406 5,985,432 6,815,731 6,566,477 Current Assets Cash and Temporary Cash Investments 71,533 46,048 Hedging Collateral Deposits — 91,670 Receivables – Net of Allowance for Uncollectible Accounts of $ 48,146 and $ 40,228 , Respectively 257,965 361,626 Unbilled Revenue 60,018 30,075 Gas Stored Underground 6,554 32,364 Materials and Supplies - at average cost 45,204 40,637 Unrecovered Purchased Gas Costs 26,851 99,342 Other Current Assets 75,233 59,369 543,358 761,131 Other Assets Recoverable Future Taxes 104,426 106,247 Unamortized Debt Expense 8,062 8,884 Other Regulatory Assets 61,497 67,101 Deferred Charges 85,053 77,472 Other Investments 74,618 95,025 Goodwill 5,476 5,476 Prepaid Pension and Post-Retirement Benefit Costs 224,701 196,597 Fair Value of Derivative Financial Instruments 42,424 9,175 Other 1,896 2,677 608,153 568,654 Total Assets $ 7,967,242 $ 7,896,262 See Notes to Condensed Consolidated Financial Statements 8 Table of Contents National Fuel Gas Company Consolidated Balance Sheets (Unaudited) March 31, 2023 September 30, 2022 (Thousands of U.S. Dollars) CAPITALIZATION AND LIABILITIES Capitalization: Comprehensive Shareholders’ Equity Common Stock, $ 1 Par Value Authorized - 200,000,000 Shares; Issued And Outstanding – 91,795,080 Shares and 91,478,064 Shares, Respectively $ 91,795 $ 91,478 Paid in Capital 1,031,341 1,027,066 Earnings Reinvested in the Business 1,810,454 1,587,085 Accumulated Other Comprehensive Loss ( 54,864 ) ( 625,733 ) Total Comprehensive Shareholders’ Equity 2,878,726 2,079,896 Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs 2,085,235 2,083,409 Total Capitalization 4,963,961 4,163,305 Current and Accrued Liabilities Notes Payable to Banks and Commercial Paper 410,000 60,000 Current Portion of Long-Term Debt — 549,000 Accounts Payable 119,497 178,945 Amounts Payable to Customers 2,830 419 Dividends Payable 43,602 43,452 Interest Payable on Long-Term Debt 14,303 17,376 Customer Advances — 26,108 Customer Security Deposits 34,382 24,283 Other Accruals and Current Liabilities 257,923 257,327 Fair Value of Derivative Financial Instruments 34,763 785,659 917,300 1,942,569 Other Liabilities Deferred Income Taxes 1,000,526 698,229 Taxes Refundable to Customers 354,274 362,098 Cost of Removal Regulatory Liability 265,626 259,947 Other Regulatory Liabilities 189,378 188,803 Other Post-Retirement Liabilities 2,977 3,065 Asset Retirement Obligations 160,910 161,545 Other Liabilities 112,290 116,701 2,085,981 1,790,388 Commitments and Contingencies (Note 8) — — Total Capitalization and Liabilities $ 7,967,242 $ 7,896,262 See Notes to Condensed Consolidated Financial Statements 9 Table of Contents National Fuel Gas Company Consolidated Statements of Cash Flows (Unaudited) Six Months Ended March 31, (Thousands of U.S. Dollars) 2023 2022 OPERATING ACTIVITIES Net Income Available for Common Stock $ 310,570 $ 299,720 Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: Depreciation, Depletion and Amortization 197,564 179,823 Deferred Income Taxes 80,745 94,212 Stock-Based Compensation 11,286 10,631 Reduction of Other Post-Retirement Regulatory Liability — ( 18,533 ) Other 10,758 14,494 Change in: Receivables and Unbilled Revenue 71,760 ( 166,584 ) Gas Stored Underground and Materials, Supplies and Emission Allowances 21,243 32,040 Unrecovered Purchased Gas Costs 72,491 29,377 Other Current Assets ( 15,864 ) ( 8,605 ) Accounts Payable ( 29,169 ) 2,006 Amounts Payable to Customers 2,411 3,401 Customer Advances ( 26,108 ) ( 17,223 ) Customer Security Deposits 10,099 1,474 Other Accruals and Current Liabilities 28,741 11,164 Other Assets ( 26,901 ) ( 32,659 ) Other Liabilities ( 8,417 ) ( 9,119 ) Net Cash Provided by Operating Activities 711,209 425,619 INVESTING ACTIVITIES Capital Expenditures ( 496,362 ) ( 415,415 ) Net Proceeds from Sale of Oil and Gas Producing Properties — 13,525 Deposit Paid for Upstream Assets ( 12,700 ) — Sale of Fixed Income Mutual Fund Shares in Grantor Trust 10,000 30,000 Other 14,413 13,689 Net Cash Used in Investing Activities ( 484,649 ) ( 358,201 ) FINANCING ACTIVITIES Proceeds from Issuance of Short-Term Note Payable to Bank 250,000 — Net Change in Other Short-Term Notes Payable to Banks and Commercial Paper 100,000 59,500 Reduction of Long-Term Debt ( 549,000 ) — Dividends Paid on Common Stock ( 87,051 ) ( 83,091 ) Net Repurchases of Common Stock ( 6,694 ) ( 9,026 ) Net Cash Used in Financing Activities ( 292,745 ) ( 32,617 ) Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash ( 66,185 ) 34,801 Cash, Cash Equivalents, and Restricted Cash at October 1 137,718 120,138 Cash, Cash Equivalents, and Restricted Cash at March 31 $ 71,533 $ 154,939 Supplemental Disclosure of Cash Flow Information Non-Cash Investing Activities: Non-Cash Capital Expenditures $ 64,495 $ 63,490 See Notes to Condensed Consolidated Financial Statements 10 Table of Contents National Fuel Gas Company Notes to Condensed Consolidated Financial Statements (Unaudited) Note 1 – Summary of Significant Accounting Policies Principles of Consolidation. The Company consolidates all entities in which it has a controlling financial interest. All significant intercompany balances and transactions are eliminated. The Company uses proportionate consolidation when accounting for drilling arrangements related to oil and gas producing properties accounted for under the full cost method of accounting. The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Earnings for Interim Periods. The Company, in its opinion, has included all adjustments (which consist of only normally recurring adjustments, unless otherwise disclosed in this Quarterly Report on Form 10-Q) that are necessary for a fair statement of the results of operations for the reported periods. The consolidated financial statements and notes thereto, included herein, should be read in conjunction with the financial statements and notes for the years ended September 30, 2022, 2021 and 2020 that are included in the Company's 2022 Form 10-K. The consolidated financial statements for the year ended September 30, 2023 will be audited by the Company's independent registered public accounting firm after the end of the fiscal year. The earnings for the six months ended March 31, 2023 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2023. Most of the business of the Utility segment is seasonal in nature and is influenced by weather conditions. Due to the seasonal nature of the heating business in the Utility segment, earnings during the winter months normally represent a substantial part of the earnings that this business is expected to achieve for the entire fiscal year. The Company’s business segments are discussed more fully in Note 9 – Business Segment Information. Consolidated Statements of Cash Flows. The components, as reported on the Company’s Consolidated Balance Sheets, of the total cash, cash equivalents, and restricted cash presented on the Statement of Cash Flows are as follows (in thousands): Six Months Ended March 31, 2023 Six Months Ended March 31, 2022 Balance at March 31, 2023 Balance at October 1, 2022 Balance at March 31, 2022 Balance at October 1, 2021 Cash and Temporary Cash Investments $ 71,533 $ 46,048 $ 52,569 $ 31,528 Hedging Collateral Deposits — 91,670 102,370 88,610 Cash, Cash Equivalents, and Restricted Cash $ 71,533 $ 137,718 $ 154,939 $ 120,138 The Company considers all highly liquid debt instruments purchased with a maturity date of generally three months or less to be cash equivalents. The Company’s restricted cash is composed entirely of amounts reported as Hedging Collateral Deposits on the Consolidated Balance Sheets. Hedging Collateral Deposits is an account title for cash held in margin accounts funded by the Company to serve as collateral for derivative financial instruments in an unrealized loss position. In accordance with its accounting policy, the Company does not offset hedging collateral deposits paid or received against related derivative financial instruments liability or asset balances. Allowance for Uncollectible Accounts. The allowance for uncollectible accounts is the Company’s best estimate of the amount of probable credit losses in the existing accounts receivable. The allowance, the majority of which is in the Utility segment, is determined based on historical experience, the age of customer accounts, other specific information about customer accounts, and the economic and regulatory environment. Account balances are charged off against the allowance approximately twelve months after the account is final billed or when it is anticipated that the receivable will not be recovered. 11 Table of Contents Activity in the allowance for uncollectible accounts for the six months ended March 31, 2023 and 2022 are as follows (in thousands): Balance at Beginning of Period Additions Charged to Costs and Expenses Discounts on Purchased Receivables Net Accounts Receivable Written-Off Balance at End of Period Six Months Ended March 31, 2023 Allowance for Uncollectible Accounts $ 40,228 $ 10,973 $ 916 $ ( 3,971 ) $ 48,146 Six Months Ended March 31, 2022 Allowance for Uncollectible Accounts $ 31,639 $ 9,684 $ 790 $ ( 630 ) $ 41,483 Gas Stored Underground. In the Utility segment, gas stored underground is carried at lower of cost or net realizable value, on a LIFO method. Gas stored underground normally declines during the first and second quarters of the year and is replenished during the third and fourth quarters. In the Utility segment, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption “Other Accruals and Current Liabilities.” Such reserve, which amounted to $ 106.8 million at March 31, 2023, is reduced to zero by September 30 of each year as the inventory is replenished. Property, Plant and Equipment. In the Company’s Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. The Company's capitalized costs relating to oil and gas producing activities, net of accumulated depreciation, depletion and amortization, were $ 2.2 billion and $ 1.9 billion at March 31, 2023 and September 30, 2022, respectively. Capitalized costs include costs related to unproved properties, which are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired. Such costs amounted to $ 73.0 million and $ 66.0 million at March 31, 2023 and September 30, 2022, respectively. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized. Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10 %, which is computed by applying prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unproved properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The gas and oil prices used to calculate the full cost ceiling are based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent non-cash impairment is required to be charged to earnings in that quarter. At March 31, 2023, the ceiling exceeded the book value of the oil and gas properties by approximately $ 2.7 billion. The estimated future net cash flows were decreased by $ 936.8 million for hedging under the ceiling test at March 31, 2023. The principal assets of the Utility, Pipeline and Storage and Gathering segments, consisting primarily of gas distribution pipelines, transmission pipelines, storage facilities, gathering lines and compressor stations, are recorded at historical cost. There were no indications of any impairments to property, plant and equipment in the Utility, Pipeline and Storage and Gathering segments at March 31, 2023. 12 Table of Contents Accumulated Other Comprehensive Loss. The components of Accumulated Other Comprehensive Loss and changes for the six months ended March 31, 2023 and 2022, net of related tax effect, are as follows (amounts in parentheses indicate debits) (in thousands): Gains and Losses on Derivative Financial Instruments Funded Status of the Pension and Other Post-Retirement Benefit Plans Total Three Months Ended March 31, 2023 Balance at January 1, 2023 $ ( 240,176 ) $ ( 53,570 ) $ ( 293,746 ) Other Comprehensive Gains and Losses Before Reclassifications 225,150 — 225,150 Amounts Reclassified From Other Comprehensive Income 13,732 — 13,732 Balance at March 31, 2023 $ ( 1,294 ) $ ( 53,570 ) $ ( 54,864 ) Six Months Ended March 31, 2023 Balance at October 1, 2022 $ ( 572,163 ) $ ( 53,570 ) $ ( 625,733 ) Other Comprehensive Gains and Losses Before Reclassifications 441,367 — 441,367 Amounts Reclassified From Other Comprehensive Income 129,502 — 129,502 Balance at March 31, 2023 $ ( 1,294 ) $ ( 53,570 ) $ ( 54,864 ) Three Months Ended March 31, 2022 Balance at January 1, 2022 $ ( 213,391 ) $ ( 63,635 ) $ ( 277,026 ) Other Comprehensive Gains and Losses Before Reclassifications ( 466,001 ) — ( 466,001 ) Amounts Reclassified From Other Comprehensive Loss 94,580 — 94,580 Other Post-Retirement Adjustment for Regulatory Proceeding — ( 5,807 ) ( 5,807 ) Balance at March 31, 2022 $ ( 584,812 ) $ ( 69,442 ) $ ( 654,254 ) Six Months Ended March 31, 2022 Balance at October 1, 2021 $ ( 449,962 ) $ ( 63,635 ) $ ( 513,597 ) Other Comprehensive Gains and Losses Before Reclassifications ( 347,518 ) — ( 347,518 ) Amounts Reclassified From Other Comprehensive Loss 212,668 — 212,668 Other Post-Retirement Adjustment for Regulatory Proceeding — ( 5,807 ) ( 5,807 ) Balance at March 31, 2022 $ ( 584,812 ) $ ( 69,442 ) $ ( 654,254 ) During the quarter ended March 31, 2022, the PaPUC concluded a regulatory proceeding that addressed the recovery of other post-employment benefit (“OPEB”) expenses in Distribution Corporation's Pennsylvania service territory. As a result of that proceeding, Distribution Corporation suspended regulatory accounting for OPEB expenses in Pennsylvania and a regulatory deferral of $ 7.4 million ($ 5.8 million after-tax) related to the funded status of Distribution Corporation’s other post-retirement benefit plans in Pennsylvania was reclassified to accumulated other comprehensive loss. For further discussion of this regulatory proceeding, refer to Note 11 — Regulatory Matters under the heading “Pennsylvania Jurisdiction.” 13 Table of Contents Reclassifications Out of Accumulated Other Comprehensive Loss. The details about the reclassification adjustments out of accumulated other comprehensive loss for the six months ended March 31, 2023 and 2022 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands): Details About Accumulated Other Comprehensive Loss Components Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Loss Affected Line Item in the Statement Where Net Income is Presented Three Months Ended March 31, Six Months Ended March 31, 2023 2022 2023 2022 Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges: Commodity Contracts ($ 18,768 ) ($ 130,271 ) ($ 177,930 ) ($ 292,899 ) Operating Revenues Foreign Currency Contracts ( 172 ) 50 ( 351 ) 90 Operating Revenues ( 18,940 ) ( 130,221 ) ( 178,281 ) ( 292,809 ) Total Before Income Tax 5,208 35,641 48,779 80,141 Income Tax Expense ($ 13,732 ) ($ 94,580 ) ($ 129,502 ) ($ 212,668 ) Net of Tax Other Current Assets . The components of the Company’s Other Current Assets are as follows (in thousands): At March 31, 2023 At September 30, 2022 Prepayments $ 14,821 $ 17,757 Prepaid Property and Other Taxes 23,218 14,321 Prepaid State Income Taxes 5,132 5,933 Regulatory Assets 32,062 21,358 $ 75,233 $ 59,369 Other Accruals and Current Liabilities . The components of the Company’s Other Accruals and Current Liabilities are as follows (in thousands): At March 31, 2023 At September 30, 2022 Accrued Capital Expenditures $ 39,232 $ 64,720 Regulatory Liabilities 39,662 31,293 Reserve for Gas Replacement 106,835 — Liability for Royalty and Working Interests 14,365 86,206 Non-Qualified Benefit Plan Liability 17,474 17,474 Other 40,355 57,634 $ 257,923 $ 257,327 Earnings Per Common Share. Basic earnings per common share is computed by dividing income or loss by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the potentially dilutive securities the Company had outstanding were restricted stock units and performance shares. For the quarter and six months ended March 31, 2023, the diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method. Restricted stock units and performance shares that are antidilutive are excluded from the calculation of diluted earnings per common share. There were 9,909 securities and 4,094 securities 14 Table of Contents excluded as being antidilutive for the quarter and six months ended March 31, 2023, respectively. There were 13,815 securities and 11,883 securities excluded as being antidilutive for the quarter and six months ended March 31, 2022, respectively. Stock-Based Compensation. The Company granted 202,259 performance shares during the six months ended March 31, 2023. The weighted average fair value of such performance shares was $ 64.28 per share for the six months ended March 31, 2023. Performance shares are an award constituting units denominated in common stock of the Company, the number of which may be adjusted over a performance cycle based upon the extent to which performance goals have been satisfied. Earned performance shares may be distributed in the form of shares of common stock of the Company, an equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company. The performance shares do not entitle the participant to receive dividends during the vesting period. The performance shares granted during the six months ended March 31, 2023 include awards that must meet a performance goal related to either relative return on capital over a three-year performance cycle ("ROC performance shares"), methane intensity and greenhouse gas emissions reductions over a three-year performance cycle ("ESG performance shares") or relative shareholder return over a three-year performance cycle ("TSR performance shares"). The performance goal related to the ROC performance shares over the three-year performance cycle is the Company’s total return on capital relative to the total return on capital of other companies in a group selected by the Compensation Committee (“Report Group”). Total return on capital for a given company means the average of the Report Group companies’ returns on capital for each twelve-month period corresponding to each of the Company’s fiscal years during the performance cycle, based on data reported for the Report Group companies in the Bloomberg database. The number of these ROC performance shares that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company. The fair value of the ROC performance shares is calculated by multiplying the expected number of shares that will be issued by the average market price of Company common stock on the date of grant reduced by the present value of forgone dividends over the vesting term of the award. The fair value is recorded as compensation expense over the vesting term of the award. The performance goal related to the ESG performance shares over the three-year performance cycle consists of two parts: reductions in the rates of intensity of methane emissions for each of the Company's operating segments, and reduction of the consolidated Company's total greenhouse gas emissions. The Company's Compensation Committee set specific target levels for methane intensity rates and total greenhouse gas emissions, and the performance goal is intended to incentivize and reward performance to the extent management achieves methane intensity and greenhouse gas reduction targets making progress towards the Company's 2030 goals. The number of these ESG performance shares that will vest and be paid out will depend upon the number of methane intensity segment targets achieved and whether the Company meets the total greenhouse gas emissions target. The fair value of these ESG performance shares is calculated by multiplying the expected number of shares that will be issued by the average market price of Company common stock on the date of grant reduced by the present value of forgone dividends over the vesting term of the award. The fair value is recorded as compensation expense over the vesting term of the award. The performance goal related to the TSR performance shares over the three-year performance cycle is the Company’s three-year total shareholder return relative to the three-year total shareholder return of the other companies in the Report Group. Three-year total shareholder return for a given company will be based on the data reported for that company (with the starting and ending stock prices over the performance cycle calculated as the average closing stock price for the prior calendar month and with dividends reinvested in that company’s securities at each ex-dividend date) in the Bloomberg database. The number of these TSR performance shares that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company. The fair value price at the date of grant for the TSR performance shares is determined using a Monte Carlo simulation technique, which includes a reduction in value for the present value of forgone dividends over the vesting term of the award. This price is multiplied by the number of TSR performance shares awarded, the result of which is recorded as compensation expense over the vesting term of the award. The Company granted 115,073 restricted stock units during the six months ended March 31, 2023. The weighted average fair value of such restricted stock units was $ 59.69 per share for the six months ended March 31, 2023. Restricted stock units represent the right to receive shares of common stock of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company) at the end of a specified time period. These restricted stock units do not entitle the participant to receive dividends during the vesting period. The fair value at the date of grant of the restricted stock units (represented by the market value of Company common stock on the date of the award) must be reduced by the present value of forgone dividends over the vesting term of the award. The fair value of restricted stock units on the date of award is recorded as compensation expense over the vesting period. 15 Table of Contents Note 2 – Asset Acquisitions and Divestitures On March 22, 2023, the Company entered into a purchase and sale agreement to acquire certain upstream assets located in Potter and Tioga counties, Pennsylvania from SWN Production Company, LLC effective as of January 1, 2023 for total consideration of $ 127.0 million, subject to certain purchase price adjustments at closing. These assets are contiguous with existing Company-owned upstream assets in Pennsylvania. The Company made a deposit of $ 12.7 million at the signing of the purchase and sale agreement and intends to finance the remaining acquisition cost using short and/or long-term borrowings. The transaction is expected to close before the end of June 2023. On June 30, 2022, the Company completed the sale of Seneca’s California assets, all of which are in the Exploration and Production segment, to Sentinel Peak Resources California LLC for a total sale price of $ 253.5 million, consisting of $ 240.9 million in cash and contingent consideration valued at $ 12.6 million at closing. The Company pursued this sale given the strong commodity price environment and the Company's strategic focus in the Appalachian Basin. Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed $ 10 million per year, with the amount of each annual payment calculated as $ 1.0 million for each $ 1 per barrel that the ICE Brent Average for each calendar year exceeds $ 95 per barrel up to $ 105 per barrel. The sale price, which reflected an effective date of April 1, 2022, was reduced for production revenues less expenses that were retained by Seneca from the effective date to the closing date. Under the full cost method of accounting for oil and natural gas properties, $ 220.7 million of the sale price at closing was accounted for as reduction of capitalized costs since the disposition did not alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center. The remainder of the sale price ($ 32.8 million) was applied against assets that are not subject to the full cost method of accounting, with the Company recognizing a gain of $ 12.7 million on the sale of such assets. The majority of this gain related to the sale of emission allowances. The Company also eliminated the asset retirement obligation associated with Seneca’s California oil and gas assets. This obligation amounted to $ 50.1 million and was accounted for as a reduction of capitalized costs under the full cost method of accounting. Note 3 – Revenue from Contracts with Customers The following tables provide a disaggregation of the Company's revenues for the quarter and six months ended March 31, 2023 and 2022, presented by type of service from each reportable segment. Quarter Ended March 31, 2023 (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 $ 259,770 $ — $ — $ — $ — $ — $ 259,770 Production of Crude Oil 526 — — — — — 526 Natural Gas Processing 209 — — — — — 209 Natural Gas Gathering Service — — 56,981 — — ( 55,253 ) 1,728 Natural Gas Transportation Service — 73,794 — 35,796 — ( 21,751 ) 87,839 Natural Gas Storage Service — 21,470 — — — ( 9,219 ) 12,251 Natural Gas Residential Sales — — — 318,649 — — 318,649 Natural Gas Commercial Sales — — — 48,966 — — 48,966 Natural Gas Industrial Sales — — — 2,768 — ( 4 ) 2,764 Other 2,815 ( 161 ) — ( 1,864 ) — ( 264 ) 526 Total Revenues from Contracts with Customers 263,320 95,103 56,981 404,315 — ( 86,491 ) 733,228 Alternative Revenue Programs — — — 2,801 — — 2,801 Derivative Financial Instruments ( 18,768 ) — — — — — ( 18,768 ) Total Revenues $ 244,552 $ 95,103 $ 56,981 $ 407,116 $ — $ ( 86,491 ) $ 717,261 16 Table of Contents Six Months Ended March 31, 2023 (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 $ 692,129 $ — $ — $ — $ — $ — $ 692,129 Production of Crude Oil 1,154 — — — — — 1,154 Natural Gas Processing 583 — — — — — 583 Natural Gas Gathering Service — — 113,394 — — ( 109,020 ) 4,374 Natural Gas Transportation Service — 149,996 — 64,174 — ( 42,568 ) 171,602 Natural Gas Storage Service — 42,756 — — — ( 18,215 ) 24,541 Natural Gas Residential Sales — — — 562,955 — — 562,955 Natural Gas Commercial Sales — — — 83,461 — — 83,461 Natural Gas Industrial Sales — — — 4,407 — ( 4 ) 4,403 Other 5,589 7 — ( 2,124 ) — ( 548 ) 2,924 Total Revenues from Contracts with Customers 699,455 192,759 113,394 712,873 — ( 170,355 ) 1,548,126 Alternative Revenue Programs — — — 5,923 — — 5,923 Derivative Financial Instruments ( 177,930 ) — — — — — ( 177,930 ) Total Revenues $ 521,525 $ 192,759 $ 113,394 $ 718,796 $ — $ ( 170,355 ) $ 1,376,119 Quarter Ended March 31, 2022 (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 $ 335,961 $ — $ — $ — $ — $ — $ 335,961 Production of Crude Oil 49,613 — — — — — 49,613 Natural Gas Processing 985 — — — — — 985 Natural Gas Gathering Service — — 52,604 — — ( 49,447 ) 3,157 Natural Gas Transportation Service — 72,671 — 41,483 — ( 18,233 ) 95,921 Natural Gas Storage Service — 21,451 — — — ( 9,253 ) 12,198 Natural Gas Residential Sales — — — 287,027 — — 287,027 Natural Gas Commercial Sales — — — 43,193 — — 43,193 Natural Gas Industrial Sales — — — 2,193 — — 2,193 Other 5,305 1,275 — ( 4,147 ) — ( 143 ) 2,290 Total Revenues from Contracts with Customers 391,864 95,397 52,604 369,749 — ( 77,076 ) 832,538 Alternative Revenue Programs — — — ( 547 ) — — ( 547 ) Derivative Financial Instruments ( 130,271 ) — — — — — ( 130,271 ) Total Revenues $ 261,593 $ 95,397 $ 52,604 $ 369,202 $ — $ ( 77,076 ) $ 701,720 17 Table of Contents Six Months Ended March 31, 2022 (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 $ 697,242 $ — $ — $ — $ — $ — $ 697,242 Production of Crude Oil 91,984 — — — — — 91,984 Natural Gas Processing 2,013 — — — — — 2,013 Natural Gas Gathering Service — — 104,829 — — ( 97,627 ) 7,202 Natural Gas Transportation Service — 138,940 — 69,257 — ( 35,858 ) 172,339 Natural Gas Storage Service — 42,251 — — — ( 18,278 ) 23,973 Natural Gas Residential Sales — — — 466,038 — — 466,038 Natural Gas Commercial Sales — — — 67,191 — — 67,191 Natural Gas Industrial Sales — — — 3,340 — — 3,340 Other 7,451 2,556 — ( 6,147 ) 6 ( 293 ) 3,573 Total Revenues from Contracts with Customers 798,690 183,747 104,829 599,679 6 ( 152,056 ) 1,534,895 Alternative Revenue Programs — — — 6,281 — — 6,281 Derivative Financial Instruments ( 292,899 ) — — — — — ( 292,899 ) Total Revenues $ 505,791 $ 183,747 $ 104,829 $ 605,960 $ 6 $ ( 152,056 ) $ 1,248,277 The Company records revenue related to its derivative financial instruments in the Exploration and Production segment. The Company also records revenue related to alternative revenue programs in its Utility segment. Revenue related to derivative financial instruments and alternative revenue programs are excluded from the scope of the authoritative guidance regarding revenue recognition since they are accounted for under other existing accounting guidance. The Company’s Pipeline and Storage segment expects to recognize the following revenue amounts in future periods related to “fixed” charges associated with remaining performance obligations for transportation and storage contracts: $ 106.0 million for the remainder of fiscal 2023; $ 206.4 million for fiscal 2024; $ 181.1 million for fiscal 2025; $ 146.9 million for fiscal 2026; $ 123.0 million for fiscal 2027; and $ 692.6 million thereafter. Note 4 – Fair Value Measurements The FASB authoritative guidance regarding fair value measurements establishes a fair-value hierarchy and prioritizes the inputs used in valuation techniques that measure fair value. Those inputs are prioritized into three levels. Level 1 inputs are unadjusted quoted prices in active markets for assets or liabilities that the Company can access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly at the measurement date. Level 3 inputs are unobservable inputs for the asset or liability at the measurement date. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. 18 Table of Contents 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 March 31, 2023 and September 30, 2022. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Recurring Fair Value Measures At fair value as of March 31, 2023 (Thousands of Dollars) Level 1 Level 2 Level 3 Netting Adjustments (1) Total (1) Assets: Cash Equivalents – Money Market Mutual Funds $ 53,519 $ — $ — $ — $ 53,519 Derivative Financial Instruments: Over the Counter Swaps – Gas — 59,179 — ( 52,327 ) 6,852 Over the Counter No Cost Collars – Gas — 56,879 — ( 26,070 ) 30,809 Contingent Consideration for Asset Sale — 5,903 — — 5,903 Foreign Currency Contracts — 213 — ( 1,353 ) ( 1,140 ) Other Investments: Balanced Equity Mutual Fund 15,924 — — — 15,924 Fixed Income Mutual Fund 15,949 — — — 15,949 Total $ 85,392 $ 122,174 $ — $ ( 79,750 ) $ 127,816 Liabilities: Derivative Financial Instruments: Over the Counter Swaps – Gas $ — $ 91,509 $ — $ ( 52,327 ) $ 39,182 Over the Counter No Cost Collars – Gas — 21,616 — ( 26,070 ) ( 4,454 ) Foreign Currency Contracts — 1,388 — ( 1,353 ) 35 Total $ — $ 114,513 $ — $ ( 79,750 ) $ 34,763 Total Net Assets/(Liabilities) $ 85,392 $ 7,661 $ — $ — $ 93,053 Recurring Fair Value Measures At fair value as of September 30, 2022 (Thousands of Dollars) Level 1 Level 2 Level 3 Netting Adjustments (1) Total (1) Assets: Cash Equivalents – Money Market Mutual Funds $ 35,015 $ — $ — $ — $ 35,015 Hedging Collateral Deposits 91,670 — — — 91,670 Derivative Financial Instruments: Over the Counter Swaps – Gas — 5,177 — ( 4,178 ) 999 Contingent Consideration for Asset Sale — 8,176 — — 8,176 Foreign Currency Contracts — 128 — ( 128 ) — Other Investments: Balanced Equity Mutual Fund 19,506 — — — 19,506 Fixed Income Mutual Fund 33,348 — — — 33,348 Total $ 179,539 $ 13,481 $ — $ ( 4,306 ) $ 188,714 Liabilities: Derivative Financial Instruments: Over the Counter Swaps – Gas $ — $ 517,464 $ — $ ( 4,178 ) $ 513,286 Over the Counter No Cost Collars – Gas — 270,453 — — 270,453 Foreign Currency Contracts — 2,048 — ( 128 ) 1,920 Total $ — $ 789,965 $ — $ ( 4,306 ) $ 785,659 Total Net Assets/(Liabilities) $ 179,539 $ ( 776,484 ) $ — $ — $ ( 596,945 ) (1) Netting Adjustments represent the impact of legally-enforceable master netting arrangements that allow the Company to net gain and loss positions held with the same counterparties. The net asset or net liability for each counterparty is recorded as an asset or liability on the Company’s balance sheet. Derivative Financial Instruments The derivative financial instruments reported in Level 2 at March 31, 2023 and September 30, 2022 include natural gas price swap agreements, natural gas no cost collars, and foreign currency contracts, all of which are used in the Company’s 19 Table of Contents Exploration and Production segment. Hedging collateral deposits of $ 91.7 million at September 30, 2022, which were associated with the price swap agreements, no cost collars and foreign currency contracts, have been reported in Level 1. The fair value of the Level 2 price swap agreements and no cost collars is based on an internal cash flow model that uses observable inputs (i.e. SOFR based discount rates for the price swap agreements and basis differential information, if applicable, at active natural gas and crude oil trading markets). The fair value of the Level 2 foreign currency contracts is determined using the market approach based on observable market transactions of forward Canadian currency rates. The authoritative guidance for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At March 31, 2023, the Company determined that nonperformance risk associated with the price swap agreements, no cost collars and foreign currency contracts would have no material impact on its financial position or results of operation. To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates. Derivative financial instruments reported in Level 2 at March 31, 2023 also includes the contingent consideration associated with the sale of the Exploration and Production segment's California assets on June 30, 2022, which is discussed at Note 2 – Asset Acquisitions and Divestitures and at Note 5 – Financial Instruments. The fair value of the contingent consideration was calculated using a Monte Carlo simulation model that uses observable inputs, including the ICE Brent closing price as of the valuation date, initial and max trigger price, volatility, risk free rate, time of maturity and counterparty risk. For the quarters ended March 31, 2023 and March 31, 2022, there were no assets or liabilities measured at fair value and classified as Level 3. Note 5 – Financial Instruments Long-Term Debt. The fair market value of the Company’s debt, as presented in the table below, was determined using a discounted cash flow model, which incorporates the Company’s credit ratings and current market conditions in determining the yield, and subsequently, the fair market value of the debt. Based on these criteria, the fair market value of long-term debt, including current portion, was as follows (in thousands): March 31, 2023 September 30, 2022 Carrying Amount Fair Value Carrying Amount Fair Value Long-Term Debt $ 2,085,235 $ 1,951,250 $ 2,632,409 $ 2,453,209 The fair value amounts are not intended to reflect principal amounts that the Company will ultimately be required to pay. Carrying amounts for other financial instruments recorded on the Company’s Consolidated Balance Sheets approximate fair value. The fair value of long-term debt was calculated using observable inputs (U.S. Treasuries for the risk free component and company specific credit spread information – generally obtained from recent trade activity in the debt). As such, the Company considers the debt to be Level 2. Any temporary cash investments, notes payable to banks and commercial paper are stated at cost. Temporary cash investments are considered Level 1, while notes payable to banks and commercial paper are considered to be Level 2. Given the short-term nature of the notes payable to banks and commercial paper, the Company believes cost is a reasonable approximation of fair value. Other Investments. The components of the Company's Other Investments are as follows (in thousands): At March 31, 2023 At September 30, 2022 Life Insurance Contracts $ 42,745 $ 42,171 Equity Mutual Fund 15,924 19,506 Fixed Income Mutual Fund 15,949 33,348 $ 74,618 $ 95,025 20 Table of Contents Investments in life insurance contracts are stated at their cash surrender values or net present value. Investments in an equity mutual fund and a fixed income mutual fund are stated at fair value based on quoted market prices with changes in fair value recognized in net income. The insurance contracts and equity mutual fund are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees. The fixed income mutual fund is primarily an informal funding mechanism for certain regulatory obligations that the Company has to Utility segment customers in its Pennsylvania jurisdiction, as discussed in Note 11 – Regulatory Matters, and for various benefit obligations the Company has to certain employees. Derivative Financial Instruments. The Company uses derivative financial instruments to manage commodity price risk in the Exploration and Production segment. The Company enters into over-the-counter no cost collar and swap agreements to manage the price risk associated with forecasted sales of natural gas. In addition, the Company also enters into foreign exchange forward contracts to manage the risk of currency fluctuations associated with transportation costs denominated in Canadian currency in the Exploration and Production segment. These instruments are accounted for as cash flow hedges. The duration of the Company’s cash flow hedges does not typically exceed 5 years while the foreign currency forward contracts do not exceed 8 years. On June 30, 2022, the Company completed the sale of Seneca’s California assets. Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed $ 10 million per year, with the amount of each annual payment calculated as $ 1.0 million for each $ 1 per barrel that the ICE Brent Average for each calendar year exceeds $ 95 per barrel up to $ 105 per barrel. The Company has determined that this contingent consideration meets the definition of a derivative under the authoritative accounting guidance. Changes in the fair value of this contingent consideration are marked-to-market each reporting period, with changes in fair value recognized in Other Income (Deductions) on the Consolidated Statement of Income. The fair value of this contingent consideration was estimated to be $ 5.9 million and $ 8.2 million at March 31, 2023 and September 30, 2022, respectively. A $ 2.5 million mark-to-market adjustment was recorded during the quarter ended March 31, 2023. A $ 2.3 million mark-to-market adjustment was recorded during the six months ended March 31, 2023. The Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at March 31, 2023 and September 30, 2022. Cash Flow Hedges For derivative financial instruments that are designated and qualify as a cash flow hedge, the gain or loss on the derivative is reported as a component of other comprehensive income (loss) and reclassified into earnings in the period or periods during which the hedged transaction affects earnings. As of March 31, 2023, the Company had 462.9 Bcf of natural gas commodity derivative contracts (swaps and no cost collars) outstanding. As of March 31, 2023, the Company was hedging a total of $ 51.0 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts. As of March 31, 2023, the Company had $ 1.3 million of net hedging losses after taxes included in the accumulated other comprehensive income (loss) balance. It is expected that $ 37.4 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. 21 Table of Contents The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Three Months Ended March 31, 2023 and 2022 (Thousands of Dollars) Derivatives in Cash Flow Hedging Relationships Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) for the Three Months Ended March 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 March 31, 2023 2022 2023 2022 Commodity Contracts $ 310,623 $ ( 642,240 ) Operating Revenue $ ( 18,768 ) $ ( 130,271 ) Foreign Currency Contracts ( 79 ) 634 Operating Revenue ( 172 ) 50 Total $ 310,544 $ ( 641,606 ) $ ( 18,940 ) $ ( 130,221 ) The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Six Months Ended March 31, 2023 and 2022 (Thousands of Dollars) Derivatives in Cash Flow Hedging Relationships Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) for the Six Months Ended March 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 Six Months Ended March 31, 2023 2022 2023 2022 Commodity Contracts $ 607,743 $ ( 479,114 ) Operating Revenue $ ( 177,930 ) $ ( 292,899 ) Foreign Currency Contracts 394 640 Operating Revenue ( 351 ) 90 Total $ 608,137 $ ( 478,474 ) $ ( 178,281 ) $ ( 292,809 ) Credit Risk The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on a quarterly basis monitors counterparty credit exposure. The majority of the Company’s counterparties are financial institutions and energy traders. The Company has over the-counter swap positions, no cost collars and applicable foreign currency forward contracts with sixteen counterparties of which eight are in a net gain position. On average, the Company had $ 4.6 million of credit exposure per counterparty in a gain position at March 31, 2023. The maximum credit exposure per counterparty in a gain position at March 31, 2023 was $ 11.1 million. As of March 31, 2023, no collateral was received from the counterparties by the Company. The Company's gain position on such derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral, nor had the counterparties' credit ratings declined to levels at which the counterparties were required to post collateral. As of March 31, 2023, fourteen of the sixteen counterparties to the Company’s outstanding derivative financial contracts (specifically the over-the-counter swaps, over-the-counter no cost collars and applicable foreign currency forward contracts) had a common credit-risk related contingency feature. In the event the Company’s credit rating increases or falls below a certain threshold (applicable debt ratings), the available credit extended to the Company would either increase or decrease. A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to post or increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments). If the Company’s outstanding derivative financial contracts with a credit-risk contingency feature were in a liability position (or 22 Table of Contents 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 March 31, 2023, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $ 7.1 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 March 31, 2023. Depending on the movement of commodity prices in the future, it is possible that these liability positions could swing into asset positions, at which point the Company would be exposed to credit risk on its derivative financial instruments. In that case, the Company's counterparties could be required to post hedging collateral deposits. The Company’s requirement to post hedging collateral deposits and the Company's right to receive hedging collateral deposits is based on the fair value determined by the Company’s counterparties, which may differ from the Company’s assessment of fair value. Note 6 – Income Taxes The effective tax rates for the quarters ended March 31, 2023 and March 31, 2022 were 26.2 % and 25.6 %, respectively. The effective tax rates for the six months ended March 31, 2023 and March 31, 2022 were 25.7 % and 25.5 % , respectively. During the quarter and six months ended March 31, 2022, the Company was able to utilize the Enhanced Oil Recovery tax credit, which was not available during the quarter and six months ended March 31, 2023 due to the sale of its California properties. On April 14, 2023, the IRS issued guidance that provides a safe harbor method of accounting that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized. The Company is currently analyzing this guidance to determine the potential impact on the financial statements. 23 Table of Contents Note 7 – Capitalization Summary of Changes in Common Stock Equity Common Stock Paid In Capital Earnings Reinvested in the Business Accumulated Other Comprehensive Income (Loss) Shares Amount (Thousands, except per share amounts) Balance at January 1, 2023 91,787 $ 91,787 $ 1,025,639 $ 1,713,176 $ ( 293,746 ) Net Income Available for Common Stock 140,880 Dividends Declared on Common Stock ($ 0.475 Per Share) ( 43,602 ) Other Comprehensive Income, Net of Tax 238,882 Share-Based Payment Expense (1) 5,200 Common Stock Issued Under Stock and Benefit Plans 8 8 502 Balance at March 31, 2023 91,795 $ 91,795 $ 1,031,341 $ 1,810,454 $ ( 54,864 ) Balance at October 1, 2022 91,478 $ 91,478 $ 1,027,066 $ 1,587,085 $ ( 625,733 ) Net Income Available for Common Stock 310,570 Dividends Declared on Common Stock ($ 0.95 Per Share) ( 87,201 ) Other Comprehensive Income, Net of Tax 570,869 Share-Based Payment Expense (1) 10,318 Common Stock Issued (Repurchased) Under Stock and Benefit Plans 317 317 ( 6,043 ) Balance at March 31, 2023 91,795 $ 91,795 $ 1,031,341 $ 1,810,454 $ ( 54,864 ) Balance at January 1, 2022 91,437 $ 91,437 $ 1,013,821 $ 1,281,963 $ ( 277,026 ) Net Income Available for Common Stock 167,328 Dividends Declared on Common Stock ($ 0.455 Per Share) ( 41,608 ) Other Comprehensive Loss, Net of Tax ( 377,228 ) Share-Based Payment Expense (1) 4,692 Common Stock Issued Under Stock and Benefit Plans 12 12 271 Balance at March 31, 2022 91,449 $ 91,449 $ 1,018,784 $ 1,407,683 $ ( 654,254 ) Balance at October 1, 2021 91,182 $ 91,182 $ 1,017,446 $ 1,191,175 $ ( 513,597 ) Net Income Available for Common Stock 299,720 Dividends Declared on Common Stock ($ 0.91 Per Share) ( 83,212 ) Other Comprehensive Loss, Net of Tax ( 140,657 ) Share-Based Payment Expense (1) 9,732 Common Stock Issued (Repurchased) Under Stock and Benefit Plans 267 267 ( 8,394 ) Balance at March 31, 2022 91,449 $ 91,449 $ 1,018,784 $ 1,407,683 $ ( 654,254 ) (1) Paid in Capital includes compensation costs associated with performance shares and/or restricted stock awards. The expense is included within Net Income Available For Common Stock, net of tax benefits. Common Stock. During the six months ended March 31, 2023, the Company issued 12,055 original issue shares of common stock as a result of SARs exercises, 113,531 original issue shares of common stock for restricted stock units that vested and 278,687 original issue shares of common stock for performance shares that vested. The Company also issued 14,680 original issue shares of common stock to the non-employee directors of the Company who receive compensation under the Company’s 2009 Non-Employee Director Equity Compensation Plan, including the reinvestment of dividends for certain non-employee directors who elected to defer their shares pursuant to the dividend reinvestment feature of the Company's Deferred Compensation Plan for Directors and Officers (the "DCP") during the six months ended March 31, 2023. In addition, the Company issued 824 original issue shares of common stock to officers of the Company who elected to defer their shares pursuant to the dividend reinvestment feature of the Company's DCP Plan during the six months ended March 31, 2023. 24 Table of Contents Holders of stock-based compensation awards will often tender shares of common stock to the Company for payment of applicable withholding taxes. During the six months ended March 31, 2023, 102,761 shares of common stock were tendered to the Company for such purposes. The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law. Short-Term Borrowings. On June 30, 2022, the Company entered into a new 364-Day Credit Agreement (the "364-Day Credit Agreement") with a syndicate of five banks, all of which are also lenders under the Credit Agreement. The 364-Day Credit Agreement provides an additional $ 250.0 million unsecured committed delayed draw term loan credit facility with a maturity date of June 29, 2023. The Company elected to draw $ 250.0 million under the facility on October 27, 2022. The Company used the proceeds for general corporate purposes, which included using $ 150.0 million for the November 2022 redemption of a portion of the Company's outstanding long-term debt with a maturity date in March 2023. Current Portion of Long-Term Debt. None of the Company's long-term debt as of March 31, 2023 had a maturity date within the following twelve-month period. The Current Portion of Long-Term Debt at September 30, 2022 consisted of $ 500.0 million of 3.75 % notes and $ 49.0 million of 7.395 % notes. The Company redeemed $ 150.0 million of the 3.75 % notes on November 25, 2022 using a portion of the proceeds from short-term borrowings, as discussed above. In March 2023, the Company redeemed the remaining $ 350.0 million of the 3.75 % notes as well as the $ 49.0 million of 7.395 % notes. Note 8 – Commitments and Contingencies Environmental Matters. The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory requirements. It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. At March 31, 2023, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $ 3.8 million. The Company's liability for such clean-up costs has been recorded in Other Liabilities on the Consolidated Balance Sheet at March 31, 2023. The Company expects to recover its environmental clean-up costs through rate recovery over a period of less than one year and is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental laws and regulations, new information or other factors could have an adverse financial impact on the Company. Northern Access Project. On February 3, 2017, Supply Corporation and Empire received FERC approval of the Northern Access project described herein. Shortly thereafter, the NYDEC issued a Notice of Denial of the federal Clean Water Act Section 401 Water Quality Certification and other state stream and wetland permits for the New York portion of the project (the Water Quality Certification for the Pennsylvania portion of the project was received in January of 2017). Subsequently, FERC issued an Order finding that the NYDEC exceeded the statutory time frame to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification. FERC denied rehearing requests associated with its Order and FERC's decisions were appealed. The Second Circuit Court of Appeals issued an order upholding the FERC waiver orders. In addition, in the Company's state court litigation challenging the NYDEC's actions with regard to various state permits, the New York State Supreme Court issued a decision finding these permits to be preempted. The Company remains committed to the project and, on June 29, 2022, received an extension of time from FERC, until December 31, 2024, to construct the project. As of March 31, 2023, the Company has spent approximately $ 55.9 million on the project, all of which is recorded on the balance sheet. Other. The Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations and other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these other matters arising in the normal course of business could have a material effect on earnings and cash flows in the period in which they are resolved, an estimate of the possible loss or range of loss, if any, cannot be made at this time. Note 9 – Business Segment Information The Company reports financial results for four segments: Exploration and Production, Pipeline and Storage, Gathering and Utility. The division of the Company’s operations into reportable segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors. 25 Table of Contents The data presented in the tables below reflect financial information for the segments and reconcile to consolidated amounts. As stated in the 2022 Form 10-K, the Company evaluates segment performance based on income before discontinued operations (when applicable). When this is not applicable, the Company evaluates performance based on net income. There have not been any changes in the basis of segmentation nor in the basis of measuring segment profit or loss from those used in the Company’s 2022 Form 10-K. A listing of segment assets at March 31, 2023 and September 30, 2022 is shown in the tables below. Quarter Ended March 31, 2023 (Thousands) Exploration and Production Pipeline and Storage Gathering Utility Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated Revenue from External Customers $ 244,552 $ 64,223 $ 1,728 $ 406,758 $ 717,261 $ — $ — $ 717,261 Intersegment Revenues $ — $ 30,880 $ 55,253 $ 358 $ 86,491 $ — $( 86,491 ) $ — Segment Profit: Net Income (Loss) $ 60,982 $ 23,858 $ 24,334 $ 31,720 $ 140,894 $( 69 ) $ 55 $ 140,880 Six Months Ended March 31, 2023 (Thousands) Exploration and Production Pipeline and Storage Gathering Utility Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated Revenue from External Customers $ 521,525 $ 131,844 $ 4,374 $ 718,376 $ 1,376,119 $ — $ — $ 1,376,119 Intersegment Revenues $ — $ 60,915 $ 109,020 $ 420 $ 170,355 $ — $( 170,355 ) $ — Segment Profit: Net Income (Loss) $ 152,174 $ 53,335 $ 49,072 $ 55,537 $ 310,118 $( 350 ) $ 802 $ 310,570 (Thousands) Exploration and Production Pipeline and Storage Gathering Utility Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated Segment Assets: At March 31, 2023 $ 2,489,665 $ 2,357,852 $ 882,405 $ 2,363,918 $ 8,093,840 $ 2,105 $( 128,703 ) $ 7,967,242 At September 30, 2022 $ 2,507,541 $ 2,394,697 $ 878,796 $ 2,299,473 $ 8,080,507 $ 2,036 $( 186,281 ) $ 7,896,262 Quarter Ended March 31, 2022 (Thousands) Exploration and Production Pipeline and Storage Gathering Utility Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated Revenue from External Customers $ 261,593 $ 67,795 $ 3,157 $ 369,092 $ 701,637 $ — $ 83 $ 701,720 Intersegment Revenues $ — $ 27,602 $ 49,447 $ 110 $ 77,159 $ — $( 77,159 ) $ — Segment Profit: Net Income (Loss) $ 71,121 $ 25,470 $ 22,092 $ 53,048 $ 171,731 $ — $( 4,403 ) $ 167,328 Six Months Ended March 31, 2022 (Thousands) Exploration and Production Pipeline and Storage Gathering Utility Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated Revenue from External Customers $ 505,791 $ 129,342 $ 7,202 $ 605,776 $ 1,248,111 $ — $ 166 $ 1,248,277 Intersegment Revenues $ — $ 54,405 $ 97,627 $ 184 $ 152,216 $ 6 $( 152,222 ) $ — Segment Profit: Net Income (Loss) $ 133,490 $ 50,637 $ 45,229 $ 75,178 $ 304,534 $( 7 ) $( 4,807 ) $ 299,720 26 Table of Contents Note 10 – Retirement Plan and Other Post-Retirement Benefits Components of Net Periodic Benefit Cost (in thousands): Retirement Plan Other Post-Retirement Benefits Three Months Ended March 31, 2023 2022 2023 2022 Service Cost $ 1,297 $ 2,190 $ 147 $ 332 Interest Cost 10,629 5,707 3,912 2,267 Expected Return on Plan Assets ( 16,648 ) ( 13,074 ) ( 6,403 ) ( 7,340 ) Amortization of Prior Service Cost (Credit) 109 134 ( 107 ) ( 107 ) Amortization of (Gains) Losses ( 1,920 ) 6,601 ( 2,189 ) ( 1,903 ) Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1) 5,378 8,418 3,493 4,274 Net Periodic Benefit Cost (Income) $ ( 1,155 ) $ 9,976 $ ( 1,147 ) $ ( 2,477 ) Retirement Plan Other Post-Retirement Benefits Six Months Ended March 31, 2023 2022 2023 2022 Service Cost $ 2,594 $ 4,379 $ 293 $ 664 Interest Cost 21,258 11,414 7,824 4,533 Expected Return on Plan Assets ( 33,297 ) ( 26,147 ) ( 12,806 ) ( 14,680 ) Amortization of Prior Service Cost (Credit) 218 268 ( 214 ) ( 214 ) Amortization of (Gains) Losses ( 3,840 ) 13,202 ( 4,378 ) ( 3,805 ) Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1) 10,756 12,838 7,314 10,519 Net Periodic Benefit Cost (Income) $ ( 2,311 ) $ 15,954 $ ( 1,967 ) $ ( 2,983 ) (1) The Company’s policy is to record retirement plan and other post-retirement benefit costs in the Utility segment on a volumetric basis to reflect the fact that the Utility segment experiences higher throughput of natural gas in the winter months and lower throughput of natural gas in the summer months. The components of net periodic benefit cost other than service cost are presented in Other Income (Deductions) on the Consolidated Statements of Income. Employer Contributions. The Company did not make any contributions to its tax-qualified, noncontributory defined benefit retirement plan (Retirement Plan) or its VEBA trusts for its other post-retirement benefits during the six months ended March 31, 2023, and does not anticipate making any such contributions during the remainder of fiscal 2023. Note 11 – Regulatory Matters New York Jurisdiction Distribution Corporation's current delivery rates in its New York jurisdiction were approved by the NYPSC in an order issued on April 20, 2017 with rates becoming effective May 1, 2017. The order provided for a return on equity of 8.7 %, and directed the implementation of an earnings sharing mechanism to be in place beginning on April 1, 2018. The order also authorized the Company to recover approximately $ 15 million annually for pension and OPEB expenses from customers. Because the Company’s future pension and OPEB costs were projected to be satisfied with existing funds held in reserve, in July 2022, Distribution Corporation made a filing with the NYPSC to effectuate a pension and OPEB surcredit to customers to offset these amounts being collected in base rates effective October 1, 2022. On September 16, 2022, the NYPSC issued an order approving the filing. The surcredit will remain in effect until modified by the NYPSC in another proceeding, or until 27 Table of Contents December 31, 2024, whichever is earlier. With the implementation of this surcredit, Distribution Corporation will no longer be funding the Retirement Plan or its VEBA trusts in its New York jurisdiction. On August 13, 2021, the NYPSC issued an order extending the date through which qualified pipeline replacement costs incurred by the Company can be recovered using the existing system modernization tracker for two years (until March 31, 2023). On December 9, 2022, the Company filed a petition with the NYPSC to effectuate a system improvement tracker through which qualified pipeline replacement costs through September 30, 2024 would be tracked and recovered, and to recover certain deferred costs associated with the existing system modernization tracker, effective April 1, 2023. The NYPSC approved the petition via order dated March 17, 2023 contingent on the Company not filing a base rate case that would result in new rates becoming effective prior to October 1, 2024. On January 19, 2023, the NYPSC issued an order in its Effects of COVID-19 on Utility Service (20-M-0266) and Energy Affordability for Low Income Utility Customers (14-M-0565) proceedings whereby a Phase 2 Utility Arrears Relief Program was authorized. Specifically, the order directed Distribution Corporation and certain other New York utilities to, among other things, address arrears on residential non-energy affordability program (EAP) ratepayer accounts that did not receive a credit under the NYPSC’s Phase 1 program and small commercial ratepayer accounts by issuing a one-time bill credit to such customers to reduce or eliminate accrued arrears through May 1, 2022. The credits shall be processed within 90 days of the effective date of the order, provided that residential non-EAP customers who had their service disconnected for non-payment in 2022 shall be allowed the opportunity to have their service reinstated in order to receive the credit through June 30, 2023. The order further directs utilities to suspend residential service terminations for non-payment while arrears credits are applied to accounts through March 1, 2023, or 30 days after credits have been applied, whichever is later. The order authorizes the utilities to recover the Phase 2 costs (the arrears credits and associated carrying charges) through a surcharge. Utilities proposed various offsets to Phase 2 program costs, and Distribution Corporation has proposed certain offsets as part of an uncollectible expense reconciliation proposal. On February 17, 2023, Distribution Corporation made a filing with the NYPSC seeking approval of its uncollectible expense reconciliation mechanism and a determination is pending. Application of the proposed offsets and collection periods will be determined when the NYPSC rules on the uncollectible expense reconciliation filing. Pennsylvania Jurisdiction Distribution Corporation’s current delivery rates in its Pennsylvania jurisdiction were approved by the PaPUC on November 30, 2006 as part of a settlement agreement that became effective January 1, 2007. On October 28, 2022, Distribution Corporation made a filing with the PaPUC seeking an increase in its annual base rate operating revenues of $ 28.1 million with a proposed effective date of December 27, 2022. On December 8, 2022, the PaPUC issued an order suspending the filing until July 27, 2023 by operation of law unless directed otherwise by the PaPUC. Following discovery, the submission of testimony and an evidentiary hearing, the parties to the proceeding agreed to a settlement that authorizes, among other things, an increase in Distribution Corporation’s annual base rate operating revenues of $ 23 million as of August 1, 2023. On April 13, 2023, Distribution Corporation filed a joint petition with the PaPUC seeking approval of the settlement on behalf of all active parties to the proceeding. The joint petition is currently pending before the PaPUC. Effective October 1, 2021, pursuant to a tariff supplement filed with the PaPUC, Distribution Corporation reduced base rates by $ 7.7 million in order to stop collecting OPEB expenses from customers. It also began to refund to customers overcollected OPEB expenses in the amount of $ 50.0 million. All matters with respect to this tariff supplement were finalized on February 24, 2022 with the PaPUC’s approval of an Administrative Law Judge’s Recommended Decision. Concurrent with that decision, the Company discontinued regulatory accounting for OPEB expenses and recorded an $ 18.5 million adjustment during the quarter ended March 31, 2022 to reduce its regulatory liability for previously deferred OPEB income amounts through September 30, 2021 and to increase Other Income (Deductions) on the consolidated financial statements by a like amount. The Company also increased customer refunds of overcollected OPEB expenses from $ 50.0 million to $ 54.0 million. All refunds specified in the tariff supplement are being funded entirely by grantor trust assets held by the Company, most of which are included in a fixed income mutual fund that is a component of Other Investments on the Company’s Consolidated Balance Sheet. With the elimination of OPEB expenses in base rates, Distribution Corporation is no longer funding the grantor trust or its VEBA trusts in its Pennsylvania jurisdiction. FERC Jurisdiction Supply Corporation’s 2020 rate settlement provides that no party may make a rate filing for new rates to be effective before February 1, 2024, except that Supply Corporation may file an NGA general Section 4 rate case to change rates if the 28 Table of Contents corporate federal income tax rate is increased. If no case has been filed, Supply Corporation must file for rates to be effective February 1, 2025. Empire’s 2019 rate settlement provides that Empire must make a rate case filing no later than May 1, 2025.