ATO

INTRODUCTION The following discussion should be read in conjunction with the condensed consolidated financial statements in this Quarterly Report on Form 10-Q and Management’s Discussion and Analysis in our Annual Report on Form 10-K for the year ended September 30, 2025. Cautionary Statement for the Purposes of the Safe Harbor under the Private Securities Litigation Reform Act of 1995 The statements contained in this Quarterly Report on Form 10-Q may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included in this Report are forward-looking statements made in good faith by us and are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. When used in this Report, or any other of our documents or oral presentations, the words “anticipate”, “believe”, “estimate”, “expect”, “forecast”, “goal”, “intend”, “objective”, “plan”, “projection”, “seek”, “strategy”, or similar words are intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the statements relating to our strategy, operations, markets, services, rates, recovery of costs, availability of gas supply, and other factors. These risks and uncertainties include the following: federal, state, and local regulatory and political trends and decisions, including the impact of rate proceedings before various state regulatory commissions; increased federal regulatory oversight and potential penalties; possible increased federal, state, and local regulation of the safety of our operations; possible significant costs and liabilities resulting from pipeline integrity and other similar programs and related repairs; the inherent hazards and risks involved in distributing, transporting, and storing natural gas; the availability and accessibility of contracted gas supplies, interstate pipeline, and/or storage services; increased competition from energy suppliers and alternative forms of energy; failure to attract and retain a qualified workforce; natural disasters, adverse weather, terrorist activities, or other events and other risks and uncertainties discussed herein, all of which are difficult to predict and many of which are beyond our control; failure of technology that affects the Company's business operations; the threat of cyber-attacks or acts of cyber-terrorism that could disrupt our business operations and information technology systems or result in the loss or exposure of confidential or sensitive customer, employee, or Company information; the impact of new cybersecurity compliance requirements; adverse weather conditions; the impact of legislation to reduce or eliminate greenhouse gas emissions or fossil fuels; the impact of climate change; the capital-intensive nature of our business; our ability to continue to access the credit and capital markets to execute our business strategy; market risks beyond our control affecting our risk management activities, including commodity price volatility, counterparty performance or creditworthiness, and interest rate risk; the concentration of our operations in Texas; the impact of adverse economic conditions on our customers; changes in the availability and price of natural gas; and increased costs of providing health care benefits, along with pension and postretirement health care benefits and increased funding requirements. Accordingly, while we believe these forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. Further, we undertake no obligation to update or revise any of our forward-looking statements whether as a result of new information, future events or otherwise. OVERVIEW Atmos Energy and our subsidiaries are engaged in the regulated natural gas distribution and pipeline and storage businesses. We distribute natural gas through sales and transportation arrangements to approximately 3.4 million residential, commercial, public authority, and industrial customers throughout our six distribution divisions, which at June 30, 2026 covered service areas located in eight states. In addition, we transport natural gas for others through our distribution and pipeline systems. We manage and review our consolidated operations through the following reportable segments: •The distribution segment is comprised of our regulated natural gas distribution and related sales operations in eight states. •The pipeline and storage segment is comprised primarily of the regulated pipeline and storage operations of our Atmos Pipeline-Texas division and our natural gas transmission operations in Louisiana. 28 Our vision is to be the safest provider of natural gas services. Our commitment to this vision requires significant levels of capital spending to modernize our natural gas distribution system and operating costs to deliver natural gas safely and reliably and in full compliance with the various safety regulations impacting our business. We have the ability to begin recovering a significant portion of our expenditures timely through rate designs and mechanisms that reduce or eliminate regulatory lag and separate the recovery of our approved rate from customer usage patterns. The execution of our capital spending program, the ability to recover these expenditures timely, and our ability to access the capital markets to satisfy our financing needs are the primary drivers that affect our financial performance. We anticipate making significant capital expenditures for the foreseeable future to modernize our distribution and transmission system, to comply with the safety rules and regulations issued by the regulatory authorities responsible for the service areas in which we operate, and to prepare to serve the growing needs of the communities we serve. Between fiscal years 2026 and 2030, we anticipate spending approximately $26 billion, with more than 80 percent dedicated to safety and reliability spending. The magnitude and allocation of these expenditures may be affected by factors such as new policy and regulations, population growth, and increased labor and materials costs. Although we believe these costs are ultimately recoverable through our rates based on the regulatory frameworks currently available to us, full recovery is not assured. CRITICAL ACCOUNTING ESTIMATES AND POLICIES Our condensed consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States. Preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses and the related disclosures of contingent assets and liabilities. We based our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from such estimates. Our critical accounting policies used in the preparation of our consolidated financial statements are described in our Annual Report on Form 10-K for the fiscal year ended September 30, 2025 and include the following: •Regulation •Pension and other postretirement plans Our critical accounting policies are reviewed periodically by the Audit Committee of our Board of Directors. There were no significant changes to these critical accounting policies during the nine months ended June 30, 2026. RESULTS OF OPERATIONS Executive Summary During the nine months ended June 30, 2026, we recorded net income of $1,227.6 million, or $7.33 per diluted share, compared to net income of $1,023.9 million, or $6.40 per diluted share for the nine months ended June 30, 2025. The 20 percent year-over-year increase in net income largely reflects positive rate outcomes driven by safety and reliability spending. Additionally, our results for the nine months ended June 30, 2026 were favorably impacted by $132.4 million as a result of Texas legislation that became effective during the third quarter of fiscal 2025 related to infrastructure spending. These increases were partially offset by increased depreciation and property tax expenses, higher spending on safety and compliance related activities, and increased employee-related costs. During the nine months ended June 30, 2026, we implemented ratemaking regulatory actions which resulted in an increase in annual operating income of $355.0 million. Additionally, as of June 30, 2026, we had ratemaking efforts in progress seeking a total increase in annual operating income of $373.4 million. Capital expenditures for the nine months ended June 30, 2026 were $3,076.3 million. Over 85 percent was invested to improve the safety and reliability of our distribution and transportation systems, with a significant portion of this investment incurred under regulatory mechanisms that reduce lag to six months or less. During the nine months ended June 30, 2026, we completed approximately $2.2 billion of long-term debt and equity financing. As of June 30, 2026, our equity capitalization was 59.8 percent. As of June 30, 2026, we had approximately $4.6 billion in total liquidity, consisting of $521.0 million in cash and cash equivalents, $936.8 million in funds available through equity forward sales agreements and $3,094.4 million in undrawn capacity under our credit facilities. The following discusses the results of operations for each of our operating segments. Distribution Segment The distribution segment is comprised of our regulated natural gas distribution and related sales operations in eight states. The primary factors that impact the results of this segment are our ability to earn our authorized rates of return, competitive factors in the energy industry, and economic conditions in our service areas. 29 Our ability to earn our authorized rates of return is based primarily on our ability to improve the rate design in our various ratemaking jurisdictions to minimize regulatory lag and, ultimately, separate the recovery of our approved rates from customer usage patterns. Improving rate design is a long-term process and is further complicated by the fact that we operate in multiple rate jurisdictions. Under our current rate design, approximately 70 percent of our distribution segment revenues are earned through the first six months of the fiscal year. Additionally, we currently recover approximately 50 percent of our distribution segment revenue, excluding gas costs, through the base customer charge, which partially separates the recovery of our approved rate from customer usage patterns. Seasonal weather patterns can also affect our distribution operations. However, the effect of weather that is above or below normal is substantially offset through weather normalization adjustments, known as WNA, which have been approved by state regulatory commissions for approximately 97 percent of our residential and commercial revenues in the following states for the following time periods: Kansas, West Texas October — May Tennessee October — April Kentucky, Mississippi, Mid-Tex November — April Louisiana December — March Virginia January — December Our distribution operations are also affected by the cost of natural gas. We are generally able to pass the cost of gas through to our customers without markup under purchased gas cost adjustment mechanisms; therefore, increases in the cost of gas are offset by a corresponding increase in revenues. Revenues in our Texas and Mississippi service areas include franchise fees and gross receipts taxes, which are calculated as a percentage of revenue (inclusive of gas costs). Therefore, the amount of these taxes included in revenues is influenced by the cost of gas and the level of gas sales volumes. We record the associated tax expense as a component of taxes, other than income. The cost of gas typically does not have a direct impact on our operating income because these costs are recovered through our purchased gas cost adjustment mechanisms. However, higher gas costs may adversely impact our accounts receivable collections, resulting in higher bad debt expense. This risk is currently mitigated by rate design that allows us to collect from our customers the gas cost portion of our bad debt expense on approximately 89 percent of our residential and commercial revenues. Additionally, higher gas costs may require us to increase borrowings under our credit facilities, resulting in higher interest expense. Finally, higher gas costs, as well as competitive factors in the industry and general economic conditions may cause customers to conserve or, in the case of industrial consumers, to use alternative energy sources. Three Months Ended June 30, 2026 compared with Three Months Ended June 30, 2025 Financial and operational highlights for our distribution segment for the three months ended June 30, 2026 and 2025 are presented below. Three Months Ended June 30 2026 2025 Change (In thousands, unless otherwise noted) Operating revenues $ 774,658 $ 767,132 $ 7,526 Purchased gas cost 237,072 255,883 (18,811) Operating expenses 428,505 415,783 12,722 Operating income 109,081 95,466 13,615 Other non-operating income 8,732 7,017 1,715 Interest charges 12,870 22,271 (9,401) Income before income taxes 104,943 80,212 24,731 Income tax expense 15,558 9,731 5,827 Net income $ 89,385 $ 70,481 $ 18,904 Consolidated distribution sales volumes — MMcf 37,376 41,008 (3,632) Consolidated distribution transportation volumes — MMcf 35,767 34,346 1,421 Total consolidated distribution throughput — MMcf 73,143 75,354 (2,211) Consolidated distribution average cost of gas per Mcf sold $ 6.34 $ 6.24 $ 0.10 30 Operating income for our distribution segment increased 14.3 percent. Key drivers for the change in operating income include: •a $21.0 million increase in rate adjustments, primarily in our Mid-Tex Division. •a $3.9 million increase related to residential customer growth, primarily in our Mid-Tex Division, and increased industrial load. Partially offset by: •a $9.4 million increase in employee-related costs primarily due to an increase in headcount and labor costs to support company growth. •a $20.0 million increase in depreciation expense and property taxes associated with increased capital investments. Additionally, our distribution segment's income before income taxes for the three months ended June 30, 2026 was favorably impacted by $26.7 million as a result of Texas legislation that became effective during the third quarter of fiscal 2025 related to infrastructure spending. This amount is reflected in the respective line items in which the costs are incurred, including operating expenses of $17.8 million and interest charges. The following table shows our operating income by distribution division, in order of total rate base, for the three months ended June 30, 2026 and 2025. The presentation of our distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes. Three Months Ended June 30 2026 2025 Change (In thousands) Mid-Tex $ 74,313 $ 48,244 $ 26,069 Kentucky/Mid-States 15,366 15,221 145 Louisiana 13,760 18,747 (4,987) West Texas 5,212 5,320 (108) Mississippi 1,803 6,967 (5,164) Colorado-Kansas 2,762 2,041 721 Other (4,135) (1,074) (3,061) Total $ 109,081 $ 95,466 $ 13,615 Nine Months Ended June 30, 2026 compared with Nine Months Ended June 30, 2025 Financial and operational highlights for our distribution segment for the nine months ended June 30, 2026 and 2025 are presented below. Nine Months Ended June 30 2026 2025 Change (In thousands, unless otherwise noted) Operating revenues $ 3,911,164 $ 3,758,995 $ 152,169 Purchased gas cost 1,605,020 1,647,490 (42,470) Operating expenses 1,281,917 1,216,273 65,644 Operating income 1,024,227 895,232 128,995 Other non-operating income 24,555 30,545 (5,990) Interest charges 66,445 86,607 (20,162) Income before income taxes 982,337 839,170 143,167 Income tax expense 186,414 147,833 38,581 Net income $ 795,923 $ 691,337 $ 104,586 Consolidated distribution sales volumes — MMcf 229,995 256,085 (26,090) Consolidated distribution transportation volumes — MMcf 114,761 118,306 (3,545) Total consolidated distribution throughput — MMcf 344,756 374,391 (29,635) Consolidated distribution average cost of gas per Mcf sold $ 6.98 $ 6.43 $ 0.55 31 Operating income for our distribution segment increased 14.4 percent. Key drivers for the change in operating income include: •a $151.7 million increase in rate adjustments, primarily in our Mid-Tex Division. •a $14.7 million increase in consumption, net of WNA. •a $13.7 million increase related to residential customer growth, primarily in our Mid-Tex Division, and increased industrial load. •an $8.2 million decrease in refunds of excess deferred taxes to customers. Partially offset by: •a $69.2 million increase in depreciation expense and property taxes associated with increased capital investments. •an $11.7 million increase in system monitoring, line locating, and other compliance-related activities. •a $9.3 million increase in employee-related costs primarily due to an increase in headcount and labor costs to support company growth. Additionally, our distribution segment's income before income taxes for the nine months ended June 30, 2026 was favorably impacted by $70.8 million as a result of Texas legislation that became effective during the third quarter of fiscal 2025 related to infrastructure spending. This amount is reflected in the respective line items in which the costs are incurred, including operating expenses of $46.8 million and interest charges. Nine Months Ended June 30 2026 2025 Change (In thousands) Mid-Tex $ 628,079 $ 490,330 $ 137,749 Kentucky/Mid-States 107,228 101,484 5,744 Louisiana 92,973 91,132 1,841 West Texas 98,002 73,556 24,446 Mississippi 68,989 92,233 (23,244) Colorado-Kansas 37,227 39,821 (2,594) Other (8,271) 6,676 (14,947) Total $ 1,024,227 $ 895,232 $ 128,995 Recent Ratemaking Developments The amounts described in the following sections represent the operating income that was requested or received in each rate filing, which may not necessarily reflect the stated amount referenced in the final order, as certain operating costs may have changed as a result of a commission’s or other governmental authority’s final ruling. During the first nine months of fiscal 2026, we implemented regulatory proceedings, resulting in a $242.8 million increase in annual operating income as summarized below. Our ratemaking outcomes include the refund (return) of excess deferred income taxes (EDIT) resulting from previously enacted tax reform legislation and do not reflect the true economic benefit of the outcomes because they do not include the corresponding income tax benefit. Rate Action Annual Increase (Decrease) in Operating Income EDIT Impact Annual Increase (Decrease) in Operating Income Excluding EDIT (In thousands) Annual formula rate mechanisms $ 253,620 $ — $ 253,620 Rate case filings (10,873) (4,009) (14,882) Other rate activity 81 — 81 $ 242,828 $ (4,009) $ 238,819 32 The following ratemaking efforts seeking $373.4 million in increased annual operating income were in progress as of June 30, 2026: Division Rate Action Jurisdiction Operating Income Requested (In thousands) Colorado-Kansas Rate Case Colorado (1) $ 17,556 Kentucky/Mid-States Infrastructure Mechanism Virginia 646 Louisiana Formula Rate Mechanism Louisiana (2) 30,845 Mid-Tex Formula Rate Mechanism Mid-Tex Cities 273,213 Mississippi Formula Rate Mechanism Mississippi 37,816 West Texas Formula Rate Mechanism West Texas Cities 13,371 $ 373,447 (1) On June 10, 2026, the Colorado Public Utilities Commission approved an operating income increase of $10.8 million effective July 1, 2026. (2) The Company implemented $30.3 million in operating income increase, subject to refund, with rates effective July 1, 2026, and anticipates receiving final commission approval during the fourth quarter of fiscal 2026. Annual Formula Rate Mechanisms As an instrument to reduce regulatory lag, formula rate mechanisms allow us to refresh our rates on an annual basis without filing a formal rate case. However, these filings still involve discovery by the appropriate regulatory authorities prior to the final determination of rates under these mechanisms. We currently have formula rate mechanisms in our Louisiana, Mississippi, and Tennessee operations and in substantially all the service areas in our Texas divisions. Additionally, we have specific infrastructure programs in substantially all of our distribution divisions with tariffs in place to permit the investment associated with these programs to have their surcharge rate adjusted annually to recover approved capital costs incurred in a prior test-year period. The following table summarizes our annual formula rate mechanisms by state: Annual Formula Rate Mechanisms State Infrastructure Programs Formula Rate Mechanisms Colorado System Safety and Integrity Rider (SSIR) — Kansas Gas System Reliability Surcharge (GSRS), System Integrity Program (SIP) — Kentucky Pipeline Replacement Program (PRP) — Louisiana (1) Rate Stabilization Clause (RSC) Mississippi System Integrity Plan (SIP) Stable Rate Filing (SRF) Tennessee (1) Annual Rate Mechanism (ARM) Texas Gas Reliability Infrastructure Program (GRIP), (1) Dallas Annual Rate Review (DARR), Rate Review Mechanism (RRM) Virginia Steps to Advance Virginia Energy (SAVE) — (1) Infrastructure mechanisms in Texas, Louisiana, and Tennessee allow for the deferral of all expenses associated with capital expenditures incurred pursuant to these rules, which primarily consists of interest, depreciation, and other taxes (Texas and Tennessee only), until the next rate proceeding (rate case or annual rate filing), at which time investment and costs would be recoverable through base rates. 33 The following annual formula rate mechanisms were implemented during the nine months ended June 30, 2026: Division Jurisdiction Test Year Ended Increase in Annual Operating Income EDIT Impact Increase in Annual Operating Income Excluding EDIT Effective Date (In thousands) 2026 Filings: Mid-Tex Environs 12/31/2025 $ 15,635 — $ 15,635 06/05/2026 Mid-Tex ATM Cities 12/31/2025 28,200 — 28,200 06/05/2026 West Texas Amarillo, Lubbock, Dalhart and Channing 12/31/2025 14,687 — 14,687 06/05/2026 West Texas Environs 12/31/2025 4,325 — 4,325 06/05/2026 Kentucky/Mid-States Tennessee ARM 09/30/2025 11,861 — 11,861 06/01/2026 Mid-Tex DARR 09/30/2025 32,050 — 32,050 06/01/2026 Colorado-Kansas Kansas SIP 12/31/2025 777 — 777 04/01/2026 Colorado-Kansas Colorado SSIR 12/31/2026 409 — 409 01/01/2026 Colorado-Kansas Kansas GSRS 06/30/2025 1,949 — 1,949 12/04/2025 Kentucky/Mid-States Kentucky PRP 09/30/2026 4,670 — 4,670 10/02/2025 Kentucky/Mid-States Virginia - SAVE 09/30/2026 549 — 549 10/01/2025 Mid-Tex Mid-Tex Cities RRM 12/31/2024 138,508 — 138,508 10/01/2025 Total 2026 Filings $ 253,620 $ — $ 253,620 Rate Case Filings A rate case is a formal request from Atmos Energy to a regulatory authority to increase rates that are charged to our customers. Rate cases may also be initiated when the regulatory authorities request us to justify our rates. This process is referred to as a “show cause” action. Adequate rates are intended to provide for recovery of the Company’s costs as well as a fair rate of return and ensure that we continue to deliver reliable, reasonably priced natural gas service safely to our customers. The following table summarizes the rate cases completed in our distribution segment during the nine months ended June 30, 2026. Division State Increase (Decrease) in Annual Operating Income EDIT Impact Increase (Decrease) in Annual Operating Income Excluding EDIT Effective Date (In thousands) 2026 Rate Case Filings: Colorado-Kansas Kansas $ 12,330 $ (3,998) $ 8,332 03/01/2026 Mississippi General Rate Case Mississippi (23,203) (11) (23,214) 12/01/2025 Total 2026 Rate Case Filings $ (10,873) $ (4,009) $ (14,882) Pipeline and Storage Segment Our pipeline and storage segment consists of the regulated pipeline and storage operations of our Atmos Pipeline–Texas Division (APT) and our natural gas transmission operations in Louisiana. APT is an intrastate pipeline in Texas with a heavy concentration in the established natural gas producing areas of central, northern, and eastern Texas, extending into or near the major producing areas of the Barnett Shale, the Texas Gulf Coast, and the Permian Basin of West Texas. APT provides transportation and storage services to our Mid-Tex Division, other third-party local distribution companies, industrial, and electric generation customers, as well as marketers and producers. Over 80 percent of this segment’s revenues are derived from these APT services. These revenues are subject to traditional ratemaking governed by the Texas Railroad Commission (RRC). As part of its pipeline operations, APT owns and operates five underground storage facilities in Texas. 34 Our natural gas transmission operations in Louisiana are comprised of a 21-mile pipeline located in the New Orleans, Louisiana area that is primarily used to aggregate gas supply for our distribution division in Louisiana under a long-term contract and, on a more limited basis, to third parties. The demand fee charged to our Louisiana distribution division for these services is subject to regulatory approval by the Louisiana Public Service Commission. We also manage two asset management plans, which have been approved by applicable state regulatory commissions. Generally, these asset management plans require us to share with our distribution customers a significant portion of the cost savings earned from these arrangements. Our pipeline and storage segment is impacted by seasonal weather patterns, competitive factors in the energy industry, and economic conditions in our Texas and Louisiana service areas. Natural gas prices do not directly impact the results of this segment as revenues are derived from the transportation and storage of natural gas. However, natural gas prices and demand for natural gas could influence the level of drilling activity in the supply areas that we serve, which may influence the level of throughput we may be able to transport on our pipelines. Further, natural gas price differences between the various hubs that we serve in Texas could influence the volumes of gas transported for shippers through our Texas pipeline system and rates for such transportation. The results of APT are also significantly impacted by the natural gas requirements of its local distribution company customers. Additionally, its operations may be impacted by the timing of when costs and expenses are incurred and when these costs and expenses are recovered through its tariffs. APT annually uses GRIP to recover capital costs incurred in the prior calendar year. On February 13, 2026, APT made a GRIP filing that covered changes in net property, plant and equipment investments from January 1, 2025 through December 31, 2025 with a requested increase in operating income of $112.2 million. On May 12, 2026, the RRC approved the Company's GRIP filing. The demand fee our Louisiana natural gas transmission pipeline charges to our Louisiana distribution division increases five percent annually and has been approved by the Louisiana Public Service Commission until September 30, 2027. Three Months Ended June 30, 2026 compared with Three Months Ended June 30, 2025 Financial and operational highlights for our pipeline and storage segment for the three months ended June 30, 2026 and 2025 are presented below. Three Months Ended June 30 2026 2025 Change (In thousands, unless otherwise noted) Mid-Tex / Affiliate transportation revenue $ 243,511 $ 207,944 $ 35,567 Third-party transportation revenue 81,735 60,422 21,313 Other revenue 7,807 4,022 3,785 Total operating revenues 333,053 272,388 60,665 Total purchased gas cost (452) (1,548) 1,096 Operating expenses 122,172 117,335 4,837 Operating income 211,333 156,601 54,732 Other non-operating income 7,281 13,083 (5,802) Interest charges 20,274 19,266 1,008 Income before income taxes 198,340 150,418 47,922 Income tax expense 45,036 34,470 10,566 Net income $ 153,304 $ 115,948 $ 37,356 Gross pipeline transportation volumes — MMcf 216,439 216,416 23 Consolidated pipeline transportation volumes — MMcf 184,526 184,105 421 Operating income for our pipeline and storage segment increased 34.9 percent. Key drivers for the change in operating income include: •a $35.1 million increase primarily due to rate adjustments from the GRIP filings approved in June 2025 and May 2026. •a $4.3 million increase due to higher capacity contracted by tariff-based customers due to their increased peak day demand. •an $18.1 million increase in APT's through-system activities primarily associated with increased spreads. 35 Partially offset by: •an $8.4 million increase in depreciation expense and property taxes associated with increased capital investments. Additionally, our pipeline and storage segment's income before income taxes for the three months ended June 30, 2026 was favorably impacted by $12.1 million as a result of Texas legislation that became effective during the third quarter of fiscal 2025 related to infrastructure spending. This amount is reflected in the respective line items in which the costs are incurred, including operating expenses of $8.6 million and interest charges. Nine Months Ended June 30, 2026 compared with Nine Months Ended June 30, 2025 Financial and operational highlights for our pipeline and storage segment for the nine months ended June 30, 2026 and 2025 are presented below. Nine Months Ended June 30 2026 2025 Change (In thousands, unless otherwise noted) Mid-Tex / Affiliate transportation revenue $ 680,779 $ 602,105 $ 78,674 Third-party transportation revenue 214,871 174,061 40,810 Other revenue 13,325 10,611 2,714 Total operating revenues 908,975 786,777 122,198 Total purchased gas cost 1,836 (638) 2,474 Operating expenses 331,384 342,161 (10,777) Operating income 575,755 445,254 130,501 Other non-operating income 31,205 38,361 (7,156) Interest charges 48,843 57,869 (9,026) Income before income taxes 558,117 425,746 132,371 Income tax expense 126,488 93,220 33,268 Net income $ 431,629 $ 332,526 $ 99,103 Gross pipeline transportation volumes — MMcf 681,829 678,457 3,372 Consolidated pipeline transportation volumes — MMcf 526,249 507,870 18,379 Operating income for our pipeline and storage segment increased 29.3 percent. Key drivers for the change in operating income include: •a $75.7 million increase primarily due to rate adjustments from the GRIP filings approved in June 2025 and May 2026. •a $12.1 million increase due to higher capacity contracted by tariff-based customers due to their increased peak day demand. •a $33.8 million increase in APT's through-system activities primarily associated with increased spreads. Partially offset by: •a $20.7 million increase in depreciation expense and property taxes associated with increased capital investments. Additionally, our pipeline and storage segment's income before income taxes for the nine months ended June 30, 2026 was favorably impacted by $61.6 million as a result of Texas legislation that became effective during the third quarter of fiscal 2025 related to infrastructure spending. This amount is reflected in the respective line items in which the costs are incurred, including operating expenses of $41.7 million and interest charges. Liquidity and Capital Resources The liquidity required to fund our working capital, capital expenditures, and other cash needs is provided from a combination of internally generated cash flows and external debt and equity financing. Additionally, we have a $1.5 billion commercial paper program and four committed revolving credit facilities with $3.1 billion in total availability from third-party lenders. The commercial paper program and credit facilities provide cost-effective, short-term financing until it can be replaced with a balance of long-term debt and equity financing that achieves the Company's desired capital structure. Additionally, we have various uncommitted trade credit lines with our gas suppliers that we utilize to purchase natural gas on a monthly basis. 36 We have a shelf registration statement on file with the Securities and Exchange Commission (SEC) that allows us to issue up to $8.0 billion in common stock and/or debt securities, which expires December 3, 2027. As of June 30, 2026, $4.5 billion of securities were available for issuance under this shelf registration statement. We also have an at-the-market (ATM) equity sales program under which we may issue and sell shares of our common stock up to an aggregate offering price of $1.7 billion (including shares of common stock that may be sold pursuant to forward sale agreements entered into in connection with the ATM equity sales program), which expires December 3, 2027. As of June 30, 2026, $506.5 million of equity was available for issuance under our existing ATM equity sales program. Additionally, as of June 30, 2026, we had $936.8 million in available proceeds from outstanding forward sale agreements. Additional details are summarized in Note 8 to the condensed consolidated financial statements. The liquidity provided by these sources is expected to be sufficient to fund the Company's working capital needs and capital expenditure program for the remainder of fiscal year 2026. Additionally, we expect to continue to be able to obtain financing upon reasonable terms as necessary. The following table presents our capitalization inclusive of short-term debt and the current portion of long-term debt as of June 30, 2026, September 30, 2025 and June 30, 2025: June 30, 2026 September 30, 2025 June 30, 2025 (In thousands, except percentages) Short-term debt $ — — % $ — — % $ — — % Long-term debt (1) 10,251,258 40.2 % 8,918,944 39.7 % 8,919,726 40.0 % Shareholders’ equity 15,258,058 59.8 % 13,558,890 60.3 % 13,385,838 60.0 % Total $ 25,509,316 100.0 % $ 22,477,834 100.0 % $ 22,305,564 100.0 % (1) Inclusive of our finance leases, but exclusive of AEK's securitized long-term debt. Cash Flows Our internally generated funds may change in the future due to a number of factors, some of which we cannot control. These factors include regulatory changes, the price for our services, demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, and other factors. Cash flows from operating, investing, and financing activities for the nine months ended June 30, 2026 and 2025 are presented below. Nine Months Ended June 30 2026 2025 Change (In thousands) Total cash provided by (used in) Operating activities $ 1,671,466 $ 1,701,332 $ (29,866) Investing activities (3,076,132) (2,593,666) (482,466) Financing activities 1,726,672 1,297,079 429,593 Change in cash and cash equivalents and restricted cash and cash equivalents 322,006 404,745 (82,739) Cash and cash equivalents and restricted cash and cash equivalents at beginning of period 203,803 308,856 (105,053) Cash and cash equivalents and restricted cash and cash equivalents at end of period $ 525,809 $ 713,601 $ (187,792) Cash flows from operating activities For the nine months ended June 30, 2026, we generated cash flow from operating activities of $1,671.5 million compared with $1,701.3 million for the nine months ended June 30, 2025. Operating cash flow decreased by $29.9 million primarily due to the timing of gas cost recoveries. Cash flows from investing activities Our capital expenditures are primarily used to improve the safety and reliability of our distribution and transmission system through pipeline replacement and system modernization and to enhance and expand our system to meet customer needs. 37 Over the last three fiscal years, over 85 percent of our capital spending has been committed to improving the safety and reliability of our system. For the nine months ended June 30, 2026, cash used for investing activities was $3,076.1 million compared to $2,593.7 million for the nine months ended June 30, 2025. Capital spending increased $478.5 million primarily as a result of increased system modernization. Cash flows from financing activities For the nine months ended June 30, 2026, our financing activities provided $1,726.7 million of cash compared with $1,297.1 million of cash provided by financing activities in the prior-year period. In the nine months ended June 30, 2026, we received approximately $2.2 billion in net proceeds from the issuance of long-term debt and equity. On October 1, 2025, We completed a public offering of $600 million of 5.45% senior notes due January 2056, and received net proceeds from the offering, after the underwriting discount and offering expenses, of $590.0 million. On June 18, 2026, we completed a public offering of $700 million of 4.75% senior notes due January 2032, and received the net proceeds from the offering, after the underwriting discount and offering expenses, of $694.0 million. Additionally, during the nine months ended June 30, 2026, we settled 7,084,863 shares that had been sold on a forward basis for net proceeds of $941.7 million. The net proceeds were used primarily to support capital spending and for other general corporate purposes. Cash dividends increased due to a 14.9 percent increase in our dividend rate and an increase in shares outstanding. In the nine months ended June 30, 2025, we received approximately $1.7 billion in net proceeds from the issuance of long-term debt and equity. We completed a public offering of $650 million of 5.00% senior notes due December 2054, and received net proceeds from the offering, after the underwriting discount and offering expenses, of $639.4 million. We also completed a public offering of $500 million of 5.20% senior notes due August 2035, and received net proceeds from the offering, after the underwriting discount and offering expenses of $493.9 million. Additionally, during the nine months ended June 30, 2025, we settled 4,907,436 shares that had been sold on a forward basis for net proceeds of $568.6 million. The net proceeds were used primarily to support capital spending and for other general corporate purposes. Cash dividends increased due to an 8.1 percent increase in our dividend rate and an increase in shares outstanding. The following table summarizes our share issuances for the nine months ended June 30, 2026 and 2025: Nine Months Ended June 30 2026 2025 Shares issued: Direct Stock Purchase Plan 32,965 37,069 1998 Long-Term Incentive Plan 261,132 275,498 Retirement Savings Plan and Trust 38,905 42,163 Equity Issuance 7,084,863 4,907,436 Total shares issued 7,417,865 5,262,166 Credit Ratings Our credit ratings directly affect our ability to obtain short-term and long-term financing, in addition to the cost of such financing. In determining our credit ratings, the rating agencies consider a number of quantitative factors, including but not limited to, debt to total capitalization, operating cash flow relative to outstanding debt, operating cash flow coverage of interest, and pension liabilities. In addition, the rating agencies consider qualitative factors such as consistency of our earnings over time, the quality of our management and business strategy, the risks associated with our businesses, and the regulatory structures that govern our rates in the states where we operate. Our debt is rated by two rating agencies: Standard & Poor’s Corporation (S&P) and Moody’s Investors Service (Moody’s). Currently, our outlook and debt ratings, which are all considered investment grade, are as follows: S&P Moody’s Senior unsecured long-term debt A- A2 Short-term debt A-2 P-1 Outlook Stable Stable A significant degradation in our operating performance or a significant reduction in our liquidity caused by more limited access to the private and public credit markets as a result of deteriorating global or national financial and credit conditions could 38 trigger a negative change in our ratings outlook or even a reduction in our credit ratings by the two credit rating agencies. This would mean more limited access to the private and public credit markets and an increase in the costs of such borrowings. A credit rating is not a recommendation to buy, sell, or hold securities. The highest investment grade credit rating is AAA for S&P and Aaa for Moody’s. The lowest investment grade credit rating is BBB- for S&P and Baa3 for Moody’s. Our credit ratings may be revised or withdrawn at any time by the rating agencies, and each rating should be evaluated independently of any other rating. There can be no assurance that a rating will remain in effect for any given period of time or that a rating will not be lowered, or withdrawn entirely, by a rating agency if, in its judgment, circumstances so warrant. Debt Covenants We were in compliance with all of our debt covenants as of June 30, 2026. Our debt covenants are described in greater detail in Note 7 to the condensed consolidated financial statements. Contractual Obligations and Commercial Commitments Except as noted in Note 11 to the condensed consolidated financial statements, there were no significant changes in our contractual obligations and commercial commitments during the nine months ended June 30, 2026. Risk Management Activities In our distribution and pipeline and storage segments, we use a combination of physical storage, fixed physical contracts, and fixed financial contracts to reduce our exposure to unusually large winter-period gas price increases. Additionally, we manage interest rate risk by periodically entering into financial instruments to effectively fix the Treasury yield component of the interest cost associated with anticipated financings. The following table shows the components of the change in fair value of our financial instruments for the three and nine months ended June 30, 2026 and 2025: Three Months Ended June 30 Nine Months Ended June 30 2026 2025 2026 2025 (In thousands) Fair value of contracts at beginning of period $ 2,608 $ 122,648 $ 3,412 $ 88,651 Contracts realized/settled 31 265 1,389 (10,536) Fair value of new contracts 5,248 3,528 5,290 3,485 Other changes in value (3,859) 5,885 (6,063) 50,726 Fair value of contracts at end of period 4,028 132,326 4,028 132,326 Netting of cash collateral — — — — Cash collateral and fair value of contracts at period end $ 4,028 $ 132,326 $ 4,028 $ 132,326 The fair value of our financial instruments at June 30, 2026 is presented below by time period and fair value source: Fair Value of Contracts at June 30, 2026 Maturity in Years Source of Fair Value Less Than 1 1-3 4-5 Greater Than 5 Total Fair Value (In thousands) Prices actively quoted $ 1,002 $ 3,026 $ — $ — $ 4,028 Prices based on models and other valuation methods — — — — — Total Fair Value $ 1,002 $ 3,026 $ — $ — $ 4,028 39 OPERATING STATISTICS AND OTHER INFORMATION The following tables present certain operating statistics for our distribution and pipeline and storage segments for the three and nine months ended June 30, 2026 and 2025. Distribution Sales and Statistical Data Three Months Ended June 30 Nine Months Ended June 30 2026 2025 2026 2025 METERS IN SERVICE, end of period Residential 3,164,048 3,129,847 3,164,048 3,129,847 Commercial 253,574 254,871 253,574 254,871 Industrial 1,465 1,462 1,465 1,462 Public authority and other 5,514 5,626 5,514 5,626 Total meters 3,424,601 3,391,806 3,424,601 3,391,806 INVENTORY STORAGE BALANCE — Bcf 72.6 59.5 72.6 59.5 SALES VOLUMES — MMcf (1) Gas sales volumes Residential 14,832 17,333 125,148 143,248 Commercial 15,697 16,781 81,738 87,188 Industrial 6,237 5,934 19,859 20,277 Public authority and other 610 960 3,250 5,372 Total gas sales volumes 37,376 41,008 229,995 256,085 Transportation volumes 37,679 36,220 120,500 124,045 Total throughput 75,055 77,228 350,495 380,130 Pipeline and Storage Operations Sales and Statistical Data Three Months Ended June 30 Nine Months Ended June 30 2026 2025 2026 2025 CUSTOMERS, end of period Industrial 92 91 92 91 Other 212 201 212 201 Total 304 292 304 292 INVENTORY STORAGE BALANCE — Bcf 1.5 1.5 1.5 1.5 PIPELINE TRANSPORTATION VOLUMES — MMcf (1) 216,439 216,416 681,829 678,457 Note to preceding tables: (1)Sales and transportation volumes reflect segment operations, including intercompany sales and transportation amounts. RECENT ACCOUNTING DEVELOPMENTS Recent accounting developments, if any, and their impact on our financial position, results of operations and cash flows are described in Note 2 to the condensed consolidated financial statements. 40