National Fuel Gas Co: Form 10-K for the period ended Sep 30, 2023

The Company and its Subsidiaries

National Fuel Gas Company (the Registrant), incorporated in 1902, is a holding company organized under the laws of the State of New Jersey. The Registrant owns directly or indirectly all of the outstanding securities of its subsidiaries. Reference to “the Company” in this report means the Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries as appropriate in the context of the disclosure. Also, all references to a certain year in this report relate to the Company’s fiscal year ended September 30 of that year unless otherwise noted.

The Company is a diversified energy company engaged principally in the production, gathering, transportation, storage and distribution of natural gas. The Company operates an integrated business, with assets centered in western New York and Pennsylvania, being used for, and benefiting from, the production and transportation of natural gas from the Appalachian Basin. Current natural gas production development activities are focused in the Marcellus and Utica shales, geological formations that are present nearly a mile or more below the surface in the Appalachian region of the United States. Pipeline development activities are designed to transport natural gas production to both existing and new markets. The common geographic footprint of the Company’s subsidiaries enables them to share management, labor, facilities and support services across various businesses and pursue coordinated projects designed to produce and transport natural gas from the Appalachian Basin to markets in the eastern United States and Canada. The Company reports financial results for four business segments: Exploration and Production, Pipeline and Storage, Gathering, and Utility.

1. The Exploration and Production segment operations are carried out by Seneca Resources Company, LLC (Seneca), a Pennsylvania limited liability company. Seneca is engaged in the exploration for, and the development and production of, primarily natural gas in the Appalachian region of the United States. At September 30, 2023, Seneca had proved developed and undeveloped reserves of 4,535,084 MMcf of natural gas and 216 Mbbl of oil.

2. The Pipeline and Storage segment operations are carried out by National Fuel Gas Supply Corporation (Supply Corporation), a Pennsylvania corporation, and Empire Pipeline, Inc. (Empire), a New York corporation. Supply Corporation and Empire provide interstate natural gas transportation services for affiliated and nonaffiliated companies through integrated natural gas pipeline systems in Pennsylvania and New York. Supply Corporation also provides storage services through its underground natural gas storage fields, and Empire provides storage service (via lease with Supply Corporation) to a nonaffiliated company.

3. The Gathering segment operations are carried out by wholly-owned subsidiaries of National Fuel Gas Midstream Company, LLC (Midstream Company), a Pennsylvania limited liability company. Through these subsidiaries, Midstream Company builds, owns and operates natural gas processing and pipeline gathering facilities in the Appalachian region.

4. The Utility segment operations are carried out by National Fuel Gas Distribution Corporation (Distribution Corporation), a New York corporation. Distribution Corporation provides natural gas utility services to approximately 754,000 customers through a local distribution system located in western New York and northwestern Pennsylvania. The principal metropolitan areas served by Distribution Corporation include Buffalo, Niagara Falls and Jamestown, New York and Erie and Sharon, Pennsylvania.

Financial information about each of the Company’s business segments can be found in Item 7, MD&A and also in Item 8 at Note M — Business Segment Information.

Revenue from one customer of the Company's Exploration and Production segment, exclusive of hedging losses transacted with separate parties, represented approximately $208 million, or 9.6%, of the Company's consolidated revenue for the year ended September 30, 2023. This one customer was also a customer of the Company's Pipeline and Storage segment, accounting for an additional $14 million, or 0.6%, of the Company's consolidated revenue for the year ended September 30, 2023.

Rates and Regulation

The Company’s businesses are subject to regulation under a wide variety of federal, state and local laws, regulations and policies. This includes federal and state agency regulations with respect to rate proceedings, project permitting and environmental requirements.

The Company is subject to the jurisdiction of the FERC with respect to Supply Corporation, Empire and some transactions performed by other Company subsidiaries. The FERC, among other things, approves the rates that Supply Corporation and Empire may charge to their gas transportation and/or storage customers. Those approved rates also impact the returns that Supply Corporation and Empire may earn on the assets that are dedicated to those operations. The operations of Distribution Corporation are subject to the jurisdiction of the NYPSC, the PaPUC and, with respect to certain transactions, the FERC. The NYPSC and the PaPUC, among other things, approve the rates that Distribution Corporation may charge to its utility customers. Those approved rates also impact the returns that Distribution Corporation may earn on the assets that are dedicated to those operations. If Supply Corporation, Empire or Distribution Corporation are unable to obtain approval from these regulators for the rates they are requesting to charge customers, particularly when necessary to cover increased costs, earnings may decrease. For additional discussion of the Pipeline and Storage and Utility segments’ rates, see Item 7, MD&A under the heading “Rate Matters” and Item 8 at Note A — Summary of Significant Accounting Policies (Regulatory Mechanisms) and Note F — Regulatory Matters.

The discussion under Item 8 at Note F — Regulatory Matters includes a description of the regulatory assets and liabilities reflected on the Company’s Consolidated Balance Sheets in accordance with applicable accounting standards. To the extent that the criteria set forth in such accounting standards are not met by the operations of the Utility segment or the Pipeline and Storage segment, as the case may be, the related regulatory assets and liabilities would be eliminated from the Company’s Consolidated Balance Sheets and such accounting treatment would be discontinued.

The FERC also exercises jurisdiction over the construction and operation of interstate gas transmission and storage facilities and possesses significant penalty authority with respect to violations of the laws and regulations it administers. The Company is also subject to the jurisdiction of the Pipeline and Hazardous Materials Safety Administration (PHMSA). PHMSA issues regulations and conducts evaluations, among other things, that set safety standards for pipelines and underground storage facilities. PHMSA may delegate this authority to a state, as it has in New York and Pennsylvania, and that state may choose to institute more stringent safety regulations for the construction, operation and maintenance of intrastate facilities. In addition to this state safety authority program, the NYPSC imposes additional requirements on the construction of certain utility facilities. Increased regulation by these agencies, and other regulators, or requested changes to construction projects, could lead to operational delays or restrictions and increase compliance costs that the Company may not be able to recover fully through rates or otherwise offset.

For additional discussion of the material effects of compliance with government environmental regulation, see Item 7, MD&A under the heading “Environmental Matters.”

The Exploration and Production Segment

The Exploration and Production segment contributed net income of $232.3 million in 2023.

Additional discussion of the Exploration and Production segment appears below in this Item 1 under the headings “Sources and Availability of Raw Materials” and “Competition: The Exploration and Production Segment,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.

The Pipeline and Storage Segment

The Pipeline and Storage segment contributed net income of $100.5 million in 2023.

The Pipeline and Storage segment generated approximately 32% of its revenues in 2023 from services provided to the Utility segment or Exploration and Production segment.

Additional discussion of the Pipeline and Storage segment appears below under the headings “Sources and Availability of Raw Materials,” “Competition: The Pipeline and Storage Segment” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.

The Gathering Segment

The Gathering segment contributed net income of $99.7 million in 2023.

The Gathering segment generated approximately 94% of its revenues in 2023 from services provided to the Exploration and Production segment.

Additional discussion of the Gathering segment appears below under the headings “Sources and Availability of Raw Materials” and “Competition: The Gathering Segment,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.

The Utility Segment

The Utility segment contributed net income of $48.4 million in 2023.

Additional discussion of the Utility segment appears below under the headings “Sources and Availability of Raw Materials,” “Competition: The Utility Segment” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.

All Other Category and Corporate Operations

The All Other category and Corporate operations incurred a net loss of $4.0 million in 2023.

Additional discussion of the All Other category and Corporate operations appears below in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.

Sources and Availability of Raw Materials

The Exploration and Production segment seeks to discover and produce raw materials (primarily natural gas) as further described in this report in Item 7, MD&A and Item 8 at Note M — Business Segment Information and Note N — Supplementary Information for Oil and Gas Producing Activities.

The Pipeline and Storage segment transports and stores natural gas owned by its customers, whose gas primarily originates in the Appalachian region of the United States, as well as other gas supply regions in the United States and Canada. Additional discussion of proposed pipeline projects appears below under “Competition: The Pipeline and Storage Segment” and in Item 7, MD&A.

The Gathering segment gathers, processes and transports natural gas that is, in large part, produced by Seneca in the Appalachian region of the United States.

Natural gas is the principal raw material for the Utility segment. In 2023, the Utility segment purchased 73.1 Bcf of gas (including 71.3 Bcf for delivery to retail customers and 1.8 Bcf used in operations) pursuant to its purchase contracts with firm delivery requirements. Gas purchased from producers and suppliers in the United States under multi-month contracts accounted for 50% of these purchases. Purchases of gas in the spot market (contracts of one month or less) accounted for 50% of the Utility segment’s 2023 purchases. Purchases from DTE Energy Trading, Inc. (24%), Vitol, Inc. (14%), Shell Energy North America US (9%), EQT Energy, LLC (9%), Emera Energy Services, Inc. (8%), J. Aron & Company (7%), Tenaska Marketing Ventures (5%), Chevron Natural Gas (5%), and NRG Business Marketing Inc. (5%), accounted for nearly 86% of the Utility segment's 2023 gas purchases. No other producer or supplier provided the Utility segment with more than 5% of its gas requirements in 2023. The Utility segment does not directly purchase gas from affiliates.

Competition

Competition in the natural gas industry exists among providers of natural gas, as well as between natural gas and other sources of energy, such as fuel oil, geothermal, solar and wind. Management believes that the reliability and affordability of natural gas support its competitive position relative to other fuels.

The Company competes on the basis of price, service and reliability, product performance and other factors. Sources and providers of energy, other than those described under this “Competition” heading, do not compete with the Company to any significant extent.

Competition: The Exploration and Production Segment

The Exploration and Production segment competes with other natural gas producers and marketers with respect to sales of natural gas. The Exploration and Production segment also competes, by competitive bidding and otherwise, with other natural gas producers with respect to exploration and development prospects and mineral leaseholds.

To compete in this environment, Seneca originates and acts primarily as operator on its prospects, maintains a portfolio of firm transportation and sales contracts in order to compete in higher priced markets, seeks to minimize the risk of exploratory efforts through partnership-type arrangements, utilizes technology for both exploratory studies and drilling operations, and seeks prospect and partnership opportunities based on size, operating expertise and financial criteria.

Competition: The Pipeline and Storage Segment

Supply Corporation competes for growth in the natural gas market with other pipeline companies transporting gas in the northeast United States and with other companies providing gas storage services. Supply Corporation has some unique characteristics which enhance its competitive position. Most of Supply Corporation’s facilities are in or near areas overlying the Marcellus and Utica shale production areas in Pennsylvania, and it has established interconnections with producers and other pipelines that provide access to these supplies and to premium off-system markets. Its facilities are also located adjacent to the Canadian border at the Niagara River providing access to markets in Canada and the northeastern and midwestern United States via the TC Energy pipeline system. Supply Corporation has developed and placed into service a number of pipeline expansion projects designed to transport natural gas to key markets in New York, Pennsylvania, the northeastern United States, Canada, and to long-haul pipelines with access to the U.S. Midwest, Mid-Atlantic and the Gulf Coast. For further discussion of Pipeline and Storage projects, refer to Item 7, MD&A under the heading “Investing Cash Flow.”

Empire competes for natural gas market growth with other pipeline companies transporting gas in the northeast United States and upstate New York in particular. Empire is well situated to provide transportation of Appalachian shale gas as well as gas supplies available at Empire’s interconnect with TC Energy at Chippawa. Empire’s geographic location provides it the opportunity to compete for service to its on-system LDC markets, as well as for a share of the gas transportation markets into Canada (via Chippawa) and into the northeastern United States. Various expansion projects on Empire have expanded it's footprint and capability, allowing Empire to serve new markets in New York and elsewhere in the Northeast, and to attach to prolific Marcellus and Utica supplies principally from Tioga and Bradford Counties in Pennsylvania. Like Supply Corporation, Empire’s expanded system facilitates transportation of natural gas to key markets within New York State, the northeastern United States and Canada.

Competition: The Gathering Segment

The Gathering segment provides gathering services for Seneca and, to a lesser extent, other producers. It competes with other companies that gather and process natural gas in the Appalachian region.

Competition: The Utility Segment

With respect to gas commodity service, in New York and Pennsylvania, both of which have implemented “unbundling” policies that allow customers to choose their gas commodity supplier, Distribution Corporation has retained a substantial majority of small sales customers. In both New York and Pennsylvania, approximately 8% of Distribution Corporation’s small-volume residential and commercial customers purchase their supplies from unregulated marketers. In contrast, almost all large-volume load is served by unregulated retail marketers. However, retail competition for gas commodity service does not pose an acute competitive threat for Distribution Corporation, because in both jurisdictions, utility cost of service is recovered through rates and charges for gas delivery service, not gas commodity service.

Competition for transportation service to large-volume customers continues with local producers or pipeline companies attempting to sell or transport gas directly to end-users located within the Utility segment’s service territories without use of the utility’s facilities (i.e., bypass). In addition, while competition with fuel oil suppliers continues to exist and competition with electrification alternatives is growing, particularly in New York State, natural gas retains its competitive position from a reliability and affordability standpoint.

The Utility segment competes in its most vulnerable markets (the large commercial and industrial markets) by offering unbundled, flexible, high quality services. The Utility segment continues to advance programs promoting the efficient use of natural gas.

Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation in jurisdictions that impact the Utility segment. In addition to the federal Inflation Reduction Act, New York, for example, adopted the Climate Leadership & Community Protection Act (CLCPA) in July 2019, which could ultimately result in increased competition from electric and geothermal forms of energy. However, given the extended time frames associated with the CLCPA's emission reduction mandates as discussed in Item 7, MD&A under the heading “Environmental Matters” and subheading “Environmental Regulation,” any meaningful competition and/or business impacts resulting from the CLCPA cannot be determined.

Seasonality

Variations in weather conditions can materially affect the volume of natural gas delivered by the Utility segment, as virtually all of its residential and commercial customers use natural gas for space heating. The effect that this has on Utility segment margins is largely mitigated by a weather normalization clause (WNC). Prior to October 2023, the weather impact on cash flow in the Utility segment was mitigated by a WNC solely in its New York rate jurisdiction. However, effective October 2023, the weather impact on cash flow in the Utility segment will also be mitigated by a WNC in its Pennsylvania rate jurisdiction. Refer to Item 8, Note A – Summary of Significant Accounting Policies under the heading “Regulatory Mechanisms” for additional discussion. Under the WNC, weather that is warmer than normal results in an upward adjustment to customers’ current bills, while weather that is colder than normal results in a downward adjustment, so that in either case projected delivery revenues calculated at normal temperatures will be largely recovered.

Volumes transported and stored by Supply Corporation and Empire may vary significantly depending on weather, without materially affecting the revenues of those companies. Supply Corporation’s and Empire’s allowed rates are based on a straight fixed-variable rate design which allows recovery of fixed costs in fixed monthly reservation charges. Variable charges based on volumes are designed to recover only the variable costs associated with actual transportation or storage of gas.

Capital Expenditures

A discussion of capital expenditures by business segment is included in Item 7, MD&A under the heading “Investing Cash Flow.”

Environmental Matters

A discussion of material environmental matters involving the Company is included in Item 7, MD&A under the heading “Environmental Matters” and in Item 8, Note L — Commitments and Contingencies.

Miscellaneous

The Utility segment has numerous municipal franchises under which it uses public roads and certain other rights-of-way and public property for the location of facilities.

The Company makes its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports, available free of charge on the Company’s website, www.nationalfuel.com (http://www.nationalfuel.com), as soon as reasonably practicable after they are electronically filed with or furnished to the SEC. The information available at the Company’s website is not part of this Form 10-K or any other report filed with or furnished to the SEC.

Human Capital

The Company aims to attract the best employees, to retain those employees through offering competitive total rewards, career development and training opportunities, while also prioritizing their safety and wellness, and to create a safe, inclusive and productive work environment for everyone. Human capital measures and objectives that the Company focuses on in managing its business include the safety of its employees, its voluntary attrition rate, the number of work stoppages, its total rewards, employee development, and diversity and inclusion. Additional information regarding the Company’s human capital measures and objectives is contained in the Company’s recently published Corporate Responsibility Report, which is available on the Company’s website, www.nationalfuel.com (http://www.nationalfuel.com). The information on the Company’s website is not, and will not be deemed to be, a part of this annual report on Form 10-K or incorporated into any of the Company’s other filings with the SEC.

Employees and Collective Bargaining Agreements

The Company and its wholly-owned subsidiaries had a total of 2,240 full-time employees at September 30, 2023.

As of September 30, 2023, 47% of the Company’s active workforce was covered under collective bargaining agreements. The Company has agreements in place with collective bargaining units in New York into February 2025, as well as with collective bargaining units in Pennsylvania into April 2026.

Safety

Safety is one of the Company’s guiding principles. In managing the business, the Company focuses on the safety of its employees, contractors and communities and has implemented safety programs and management practices to promote a culture of safety. This includes required trainings for both field and office employees, as well as specific qualifications and certifications for field employees and applicable contractors. The Company also ties executive compensation to safety related goals to emphasize the importance of and focus on safety at the Company.

Voluntary Attrition Rate

The Company measures the voluntary attrition rate of its employees in assessing the Company’s overall human capital. The Company's voluntary attrition rate was 8.7% (not including retirements), which is comparable to last year’s voluntary attrition rate of 8%. The Company continues to actively monitor employee metrics, including attrition rate, to ensure proper management of and responsiveness to human capital matters.

No Work Stoppages

During fiscal 2023, the Company did not incur any work stoppages (strikes or lockouts) and therefore experienced zero idle days for the fiscal year.

Total Rewards

To attract employees and meet the needs of the Company’s workforce, the Company offers market-competitive benefits packages to employees of its subsidiaries. The Company’s benefits package options may vary depending on type of employee and date of hire. Additionally, the Company continuously looks for ways to improve employee work-life balance and well-being, and periodically conducts employee surveys to provide additional insight into employee perspectives and interest in desired benefits.

The Company's compensation program for salaried employees is intended to align employee compensation with the market while providing greater incentive to the Company’s employees to work toward the achievement of Company goals. These goals include the coordinated business goals and ESG objectives of the Company's business segments as a whole. This meaningful investment illustrates the Company’s view that attracting, retaining and motivating our employees is integral to the Company’s success.

Employee Development

The Company provides its employees with tools and development resources to enhance their skills and careers at the Company, including: (i) encouraging employees to discuss their professional development and identify interests or possible cross-training areas during annual performance reviews with their supervisors; (ii) offering corporate and technical training programs based on position, regulatory environment, and employee needs; (iii) providing a tuition aid program for educational pursuits related to present work or possible future positions; (iv) providing talent review and succession planning; (v) providing opportunities for on-the-job growth, through stretch assignments or temporary projects outside of an employee’s typical responsibilities; and (vi) offering one-on-one meetings for supervisory employees at the Company’s subsidiaries to discuss career pathing and employee development.

Diversity, Equity and Inclusion

The Company recognizes that a diverse talent pool provides the opportunity to gain a diversity of perspectives, ideas and solutions to help the Company succeed. The Company’s focus on building a diverse and inclusive culture is reflected in the Company's approach to Board diversity, its adoption of specific diversity and inclusion performance goals as part of the Company’s executive compensation program, and policies and training that reinforce the Company’s commitment to diversity and inclusion in the workplace. The Company’s policies prohibit discrimination or harassment against any employee or applicant on the basis of sex, race/ethnicity, and other protected categories. The Company communicates to employees its commitment to a harassment free workplace through the onboarding process, annual distribution and acknowledgement of the Company’s Non-Discrimination and Anti-Harassment Policy, and training for all employees including management. Additionally, to ensure transparency over time, the Company publicly discloses gender, racial and ethnic minority representation, and multi-generational workforce metrics in the Company’s Corporate Responsibility Report.

The Company's Diversity and Inclusion team continues to spearhead diversity and inclusion initiatives to help attract candidates within diverse communities, encourage partnerships with diverse vendors and suppliers and provide tools and trainings designed to promote equity and inclusion within employment teams. The Company also supports multiple active Employee Resource Groups for women, ethnically diverse employees, veterans and employees who identify as LGBTQ+, where employees can network, build community and seek support. Each group is voluntary, employee-led, open to allies, and has an executive sponsor to help facilitate communication directly to senior management.

Executive Officers of the Company as of November 15, 2023(1)

(1) The executive officers serve at the pleasure of the Board of Directors. The information provided relates to the Company and its principal subsidiaries. Many of the executive officers also have served, or currently serve, as officers or directors of other subsidiaries of the Company.

STRATEGIC RISKS

The Company is dependent on capital and credit markets to successfully execute its business strategies.

The Company relies upon short-term bank borrowings, commercial paper markets and longer-term capital markets to finance capital requirements not satisfied by cash flow from operations. The Company is dependent on these capital sources to provide capital to its subsidiaries to fund operations, acquire, maintain and develop properties, and execute growth strategies. The availability and cost of credit sources may be cyclical and these capital sources may not remain available to the Company. Turmoil in credit markets may make it difficult for the Company to obtain financing on acceptable terms or at all for working capital, capital expenditures and other investments, or to refinance existing debt. These difficulties could adversely affect the Company's growth strategies, operations and financial performance.

The Company's ability to borrow under its credit facilities and commercial paper agreements, and its ability to issue long-term debt under its indentures, depend on the Company's compliance with its obligations under the facilities, agreements and indentures. For example, to issue incremental long-term debt, the Company must meet an interest coverage test under its 1974 indenture. In general, the Company’s operating income, subject to certain adjustments, over a consecutive 12-month period within the 15 months preceding the debt issuance, must be not less than two times the total annual interest charges on the Company’s long-term debt, taking into account the incremental issuance. In addition, taking into account the incremental issuance, and using a pro forma balance sheet as of the last day of the 12-month period used in the interest coverage test, the Company must maintain a ratio of long-term debt to consolidated assets (as defined under the 1974 indenture) of not more than 60%. The 1974 indenture defines consolidated assets as total assets less a number of items, including current and accrued liabilities. Depending on their magnitude, factors that reduce the Company’s operating income and/or total assets, including impairments (i.e., write-downs) of the Company’s natural gas properties, or that increase current and accrued liabilities, like short-term borrowings and "out of the money" derivative financial instruments, could contribute to the Company’s inability to meet the interest coverage test or debt-to-assets ratio.

In addition, the Company's short-term bank loans and commercial paper are in the form of floating rate debt or debt that may have rates fixed for very short periods of time, resulting in exposure to interest rate fluctuations in the absence of interest rate hedging transactions. The cost of long-term debt, the interest rates on the Company's short-term bank loans and commercial paper, and the ability of the Company to issue commercial paper are affected by its credit ratings published by S&P, Moody's Investors Service, Inc. and Fitch Ratings, Inc. A downgrade in the Company's credit ratings could increase borrowing costs, restrict or eliminate access to commercial paper markets, negatively impact the availability of capital from uncommitted sources, and require the Company’s subsidiaries to post letters of credit, cash or other assets as collateral with certain counterparties. Additionally, $1.4 billion of the Company’s outstanding long-term debt would be subject to an interest rate increase if certain fundamental changes occur that involve a material subsidiary and result in a downgrade of a credit rating assigned to the notes below investment grade. In addition to the $1.4 billion, another $500 million of the Company’s outstanding long-term debt would be subject to an interest rate increase based solely on a downgrade of a credit rating assigned to the notes below investment grade, regardless of any additional fundamental changes.

Climate change, and the regulatory, legislative, consumer behaviors and capital access developments related to climate change, may adversely affect operations and financial results.

Climate change, and the laws, regulations and other initiatives to address climate change, may impact the Company’s financial results. In early 2021, the U.S. rejoined the Paris Agreement, the international effort to establish emissions reduction goals for signatory countries. Under the Paris Agreement, signatory countries are expected to submit their nationally determined contributions to curb greenhouse gas emissions and meet the agreed temperature objectives every five years. On April 22, 2021, the federal administration announced the U.S. nationally determined contribution to achieve a fifty to fifty-two percent reduction from 2005 levels in economy-wide net greenhouse gas pollution by 2030. Executive orders from the federal administration, in addition to federal, state and local legislative and regulatory initiatives proposed or adopted in an attempt to limit the effects of climate change, including greenhouse gas emissions, could have significant impacts on the energy industry including government-imposed limitations, prohibitions or moratoriums on the use and/or production of natural gas, establishment of a carbon tax and/or methane fee, lack of support for system modernization, as well as accelerated depreciation of assets and/or stranded assets.

Federal and state legislatures have from time to time considered bills that would establish a cap-and-trade program, cap-and-invest program, methane fee or carbon tax to incent the reduction of greenhouse gas emissions. For example, in August 2022, the federal Inflation Reduction Act was signed into law, which includes a methane charge that is expected to be applicable to the reported annual methane emissions of certain oil and gas facilities, above specified methane intensity thresholds, starting in calendar year 2024.

A number of states have also adopted energy strategies or plans with goals that include the reduction of greenhouse gas emissions. For example, Pennsylvania has a methane reduction framework for the natural gas industry which has resulted in permitting changes with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines. Furthermore, in 2019, the New York State legislature passed the CLCPA, which created emission reduction and electrification mandates, and could ultimately impact the Utility segment’s customer base and business. Pursuant to the CLCPA, New York's Climate Action Council (“CAC”) approved a final scoping plan that includes recommendations to strategically downsize and decarbonize the natural gas system and curtail use of natural gas and natural gas appliances. The final scoping plan was approved on December 19, 2022 and includes detailed recommendations to meet the CLCPA’s emissions reduction targets in the transportation, buildings, electricity, industry, agriculture & forestry and waste sectors. The final scoping plan also recommends statewide and cross-sector policies relevant to gas system transition, economywide strategies, land use, local government and adaptation and resilience. Additionally, the scoping plan recommends the implementation of a cap-and-invest program in New York. In January 2023, New York’s Governor directed the NYDEC and the New York State Energy Research and Development Authority to advance an economywide cap-and-invest program that establishes a declining cap on greenhouse gas emissions, and invests in programs to drive emissions reductions. If this proposed program or a similar program becomes effective and the Company becomes subject to new or revised cap-and-trade programs, cap-and-invest programs, methane charges, fees for carbon-based fuels or other similar costs or charges, the Company may experience additional costs and incremental operating expenses, which would impact our future earnings and cash flows, and may also experience decreased revenue in the event that implementation of these policies leads to reduced demand for natural gas.

In addition to the scoping plan, legislation or regulation that aims to reduce greenhouse gas emissions could also include natural gas bans, greenhouse gas emissions limits and reporting requirements, carbon taxes and/or similar fees on carbon dioxide, methane or equivalent emissions, restrictive permitting, increased efficiency standards requiring system remediation and/or changes in operating practices, and incentives or mandates to conserve energy or use renewable energy sources. For example, in May 2023, New York State passed legislation that prohibits the installation of fossil fuel burning equipment and building systems in new buildings commencing on or after December 31, 2025, subject to various exemptions. While the Company does not currently expect that this legislation will have a substantial impact on its financial results or operations, future legislation or regulation that aims to reduce natural gas demand or to impose additional operations requirements or restrictions on natural gas facilities, if effectuated, could impact our future earnings and cash flows.

Additionally, the trend toward increased energy conservation, change in consumer behaviors, competition from renewable energy sources, and technological advances to address climate change may reduce the demand for natural gas, which could impact our future earnings and cash flows. For further discussion of the risks associated with environmental regulation to address climate change, refer to Item 2, MD&A under the heading “Environmental Matters.”

Further, recent trends directed toward a low-carbon economy could shift funding away from, or limit or restrict certain sources of funding for, companies focused on fossil fuel-related development or carbon-intensive investments. To the extent financial markets view climate change and greenhouse gas emissions as a financial risk, the Company’s cost of and access to capital could be negatively impacted.

Organized opposition to the natural gas industry could have an adverse effect on Company operations.

Organized opposition to the natural gas industry, including exploration and production activity, pipeline expansion and replacement projects, and the extension and continued operation of natural gas distribution systems, may continue to increase as a result of, among other things, safety incidents involving natural gas facilities, and concerns raised by policymakers, financial institutions and advocacy groups about greenhouse gas emissions, hydraulic fracturing, or fossil fuels generally. This opposition may lead to increased regulatory and legislative initiatives that could place limitations, prohibitions or moratoriums on the use of natural gas, impose costs tied to carbon emissions, provide cost advantages to alternative energy sources, or impose mandates that increase operational costs associated with new natural gas infrastructure and technology. There are also increasing litigation risks associated with climate change concerns and related disclosures. Increased litigation could cause operational delays or restrictions, and increase the Company’s operating costs. In turn, these factors could impact the competitive position of natural gas, ultimately affecting the Company’s results of operations and cash flows.

Delays or changes in plans or costs with respect to Company projects, including regulatory delays or denials with respect to necessary approvals, permits or orders, could delay or prevent anticipated project completion, as well as the renewal or modification of key permits for ongoing operations, and may result in asset write-offs and reduced earnings.

Construction of planned distribution, gathering, and transmission pipeline and storage facilities, as well as the expansion and replacement of existing facilities, and the development of new natural gas wells, is subject to various regulatory, environmental, political, legal, economic and other development risks, including the ability to obtain necessary approvals and permits from regulatory agencies on a timely basis and on acceptable terms, or at all. Existing or potential third-party opposition, such as opposition from landowner and environmental groups, which are beyond our control, could materially affect the anticipated construction of a project as well as the renewal or modification of key permits for ongoing operations. In addition, third parties could impede the Company’s acquisition, expansion or renewal of rights-of-way or land rights on a timely basis and on acceptable terms. Any delay in project development or construction may prevent a planned project from going into service when anticipated, which could cause a delay in the receipt of revenues from those facilities, result in increased project costs due to extended construction timeframes, asset write-offs and materially impact operating results or anticipated results. Additionally, delays in pipeline construction projects or gathering facility completion could impede the Exploration and Production segment's ability to transport its production to premium markets, or to fulfill obligations to sell at contracted delivery points.

FINANCIAL RISKS

As a holding company, the Company depends on its operating subsidiaries to meet its financial obligations.

The Company is a holding company with no significant assets other than the stock of its operating subsidiaries. In order to meet its financial needs, the Company relies exclusively on repayments of principal and interest on intercompany loans made by the Company to its operating subsidiaries and income from dividends. Such operating subsidiaries may not generate sufficient net income to pay dividends to the Company or generate sufficient cash flow to make payments of principal or interest on such intercompany loans.

The Company may be adversely affected by economic conditions and their impact on our suppliers and customers.

Periods of slowed economic activity generally result in decreased energy consumption, particularly by industrial and large commercial companies. As a consequence, national or regional recessions or other downturns in economic activity could adversely affect the Company’s revenues and cash flows or restrict its future growth. Additionally, supply chain disruptions, and the associated costs and inflation related thereto, could have an impact on the Company's operations. Economic conditions in the Company’s utility service territories, along with legislative and regulatory prohibitions and/or limitations on terminations of service, also impact its collections of accounts receivable. Customers of the Company’s Utility segment may have particular trouble paying their bills during periods of declining economic activity, high inflation, or high commodity prices, potentially resulting in increased bad debt expense and reduced earnings. Similarly, if reductions were to occur in funding of the federal Low Income Home Energy Assistance Program, bad debt expense could increase and earnings could decrease. In addition, exploration and production companies that are customers of the Company’s Pipeline and Storage segment may decide not to renew contracts for the same transportation capacity. Certain customers of the Company's Exploration and Production segment can represent a concentrated risk during times of high commodity prices and high hedging losses. Any of these events or circumstances could have or contribute to a material adverse effect on the Company’s results of operations, financial condition and cash flows.

Changes in interest rates may affect the Company’s financing and its regulated businesses’ rates of return.

Rising interest rates may impair the Company’s ability to cost-effectively finance capital expenditures and may increase the rates at which the Company can refinance maturing debt. In addition, the Company’s authorized rate of return in its regulated businesses is based upon certain assumptions regarding interest rates. If interest rates are lower than assumed rates, the Company’s authorized rate of return could be reduced. If interest rates are higher than assumed rates, the Company’s ability to earn its authorized rate of return may be adversely impacted.

Fluctuations in natural gas prices could adversely affect revenues, cash flows and profitability.

Financial results in the Company’s Exploration and Production segment are materially dependent on prices received for its natural gas production. Both short-term and long-term price trends affect the economics of exploring for, developing, producing, and gathering natural gas. Natural gas prices can be volatile and can be affected by various factors, including weather conditions, natural disasters, consumer demand, national and worldwide economic conditions, economic disruptions caused by terrorist activities, acts of war or major accidents, domestic and foreign political conditions and events, the price and availability of alternative fuels, the proximity to, and availability of, sufficient capacity on transportation and liquefaction facilities, regional and global levels of supply and demand, energy conservation measures, and government regulations. The Company sells the natural gas that it produces at a combination of current market prices, indexed prices or through fixed-price contracts. The Company hedges a significant portion of future sales that are based on indexed prices utilizing the physical sale counter-party and/or the financial markets. The prices the Company receives depend upon factors beyond the Company’s control, including the factors affecting price mentioned above. Any prolonged reduction in natural gas prices could result in the Company reducing the level of exploration and production activity the Company otherwise would pursue, which could have a material adverse effect on its future revenues, cash flows and results of operations.

In the Company’s Pipeline and Storage segment, significant changes in the price differential between equivalent quantities of natural gas at different geographic locations could adversely impact the Company. For example, if the price of natural gas at a particular receipt point on the Company’s pipeline system increases relative to the price of natural gas at other locations, then the volume of natural gas received by the Company at the relatively more expensive receipt point may decrease, or the Company may need to discount the approved tariff rate for that transportation path in the future in order to maintain the existing volumes on its system. Changes in price differentials can cause shippers to seek alternative lower priced natural gas supplies and, consequently, alternative transportation routes. In some cases, shippers may decide not to renew transportation contracts due to changes in price differentials. While much of the impact of lower volumes under existing contracts would be offset by the straight fixed-variable rate design, this rate design does not protect Supply Corporation or Empire where shippers do not contract for expiring capacity at the same quantity and rate. If contract renewals were to decrease, revenues and earnings in this segment may decrease. Significant changes in the price differential between futures contracts for gas having different delivery dates could also adversely impact the Company. For example, if the prices of natural gas futures contracts for winter deliveries to locations served by the Pipeline and Storage segment decline relative to the prices of such contracts for summer deliveries (as a result, for instance, of increased production of gas within the segment’s geographic area or other factors), then demand for the Company’s natural gas storage services driven by that price differential could decrease. These changes could adversely affect future revenues, cash flows and results of operations.

In the Company’s Utility segment, during periods when natural gas prices are significantly higher than historical levels, customer demand could be reduced, thereby decreasing revenue. Customers may also have trouble paying the resulting higher bills when gas prices are higher or in periods of economic uncertainty, which could increase bad debt expenses and could ultimately reduce earnings. Additionally, increases in the cost of purchased gas affect cash flows and can therefore impact the amount or availability of the Company’s capital resources.

The Company has significant transactions involving price hedging of its natural gas production as well as its fixed price sale commitments.

To protect itself to some extent against price volatility and to lock in fixed pricing on natural gas production for certain periods of time, the Company’s Exploration and Production segment regularly enters into commodity price derivatives contracts (hedging arrangements) with respect to a portion of its expected production. These contracts may extend over multiple years, covering a substantial majority of the Company’s expected natural gas production over the course of the current fiscal year, and lesser percentages of subsequent years' expected production. These contracts reduce exposure to subsequent price drops but can also limit the Company’s ability to benefit from increases in commodity prices.

The nature of these hedging contracts could lead to potential liquidity impacts in scenarios of significantly increased natural gas prices if the Company has hedged its current production at prices below the current market price. Hedging collateral deposits represent the cash, letters of credit, or other eligible instruments held in Company funded margin accounts to serve as collateral for hedging positions used in the Company’s Exploration and Production segment. A significant increase in natural gas prices may cause the Company’s outstanding derivative instrument contracts to be in a liability position creating margin calls on the Company’s hedging arrangements, which could require the Company to temporarily post significant amounts of cash collateral with our hedge counterparties. That collateral could be in excess of the Company’s available short-term liquidity under its committed credit facility and other uncommitted sources of capital, leading to potential default under certain of its hedging arrangements. That interest-bearing cash collateral is returned to us in whole or in part upon a reduction in forward market prices, depending on the amount of such reduction, or in whole upon settlement of the related derivative contract.

Use of energy commodity price hedges also exposes the Company to the risk of nonperformance by a contract counterparty. These parties might not be able to perform their obligations under the hedge arrangements.

In the Exploration and Production segment, under the Company’s hedging guidelines, commodity derivatives contracts must be confined to the price hedging of existing and forecast production. The Company maintains a system of internal controls to monitor compliance with its policy. However, unauthorized speculative trades, if they were to occur, could expose the Company to substantial losses to cover positions in its derivatives contracts. In addition, in the event the Company’s actual production of natural gas falls short of hedged volumes, the Company may incur substantial losses to cover its hedges to the extent the hedges are in a loss position.

The Dodd-Frank Act increased federal oversight and regulation of the over-the-counter derivatives markets and certain entities that participate in those markets. Although regulators have issued certain regulations, other rules that may be relevant to the Company have yet to be finalized. For discussion of the risks associated with the Dodd-Frank Act, refer to Item 7, MD&A under the heading “Market Risk Sensitive Instruments.”

You should not place undue reliance on reserve information because such information represents estimates.

This Form 10-K contains estimates of the Company’s proved natural gas reserves and the future net cash flows from those reserves, which the Company’s petroleum engineers prepared and independent petroleum engineers audited. Petroleum engineers consider many factors and make assumptions in estimating natural gas reserves and future net cash flows. These factors include: historical production from the area compared with production from other producing areas; the assumed effect of governmental regulation; and assumptions concerning natural gas prices, production and development costs, severance and excise taxes, and capital expenditures. Changes in natural gas prices impact the quantity of economic natural gas reserves. Estimates of reserves and expected future cash flows prepared by different engineers, or by the same engineers at different times, may differ substantially. Ultimately, actual production, revenues and expenditures relating to the Company’s reserves will vary from any estimates, and these variations may be material. Accordingly, the accuracy of the Company’s reserve estimates is a function of the quality of available data and of engineering and geological interpretation and judgment.

If conditions remain constant, then the Company is reasonably certain that its reserve estimates represent economically recoverable natural gas reserves and future net cash flows. If conditions change in the future, then subsequent reserve estimates may be revised accordingly. You should not assume that the present value of future net cash flows from the Company’s proved reserves is the current market value of the Company’s estimated natural gas reserves. In accordance with SEC requirements, the Company bases the estimated discounted future net cash flows from its proved reserves on a 12-month average of historical prices for natural gas (based on first day of the month prices and adjusted for hedging) and on costs as of the date of the estimate, which are all discounted at the SEC mandated discount rate. Actual future prices and costs may differ materially from those used in the net present value estimate. Any significant price changes will have a material effect on the present value of the Company’s reserves.

Petroleum engineering is a subjective process of estimating underground accumulations of natural gas and other hydrocarbons that cannot be measured in an exact manner. The process of estimating natural gas reserves is complex. The process involves significant assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Future economic and operating conditions are uncertain, and changes in those conditions could cause a revision to the Company’s reserve estimates in the future. Estimates of economically recoverable natural gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including historical production from the area compared with production from other comparable producing areas, and the assumed effects of regulations by governmental agencies. Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating reserves: the quantities of natural gas that are ultimately recovered, the timing of the recovery of natural gas reserves, the production and operating costs to be incurred, the amount and timing of future development and abandonment expenditures, and the price received for the production.

Financial accounting requirements regarding exploration and production activities may affect the Company's profitability.

The Company accounts for its exploration and production activities under the full cost method of accounting. Each quarter, the Company must perform a "ceiling test" calculation, comparing the level of its unamortized investment in oil and natural gas properties to the present value of the future net revenue projected to be recovered from those properties according to methods prescribed by the SEC. In determining present value, the Company uses a 12-month historical average price for oil and natural gas (based on first day of the month prices and adjusted for hedging) as well as the SEC mandated discount rate. If, at the end of any quarter, the amount of the unamortized investment exceeds the net present value of the projected future cash flows, such investment may be considered to be "impaired," and the full cost authoritative accounting and reporting guidance require that the investment must be written down to the calculated net present value. Such an instance would require the Company to recognize an immediate expense in that quarter, and its earnings would be reduced. Depending on the magnitude of any decrease in average prices, that charge could be material. Under the Company's existing indenture covenants, an impairment could restrict the Company's ability to issue incremental long-term unsecured indebtedness for a period of time, beginning with the fourth calendar month following the impairment. In addition, because an impairment results in a charge to retained earnings, it lowers the Company's total capitalization, all other things being equal, and increases the Company's debt to capitalization ratio. As a result, an impairment can impact the Company's ability to maintain compliance with the debt to capitalization covenant set forth in its committed credit facility. The Company last recognized non-cash, pre-tax impairment charges on its oil and natural gas properties in fiscal years 2020 and 2021, in the amounts of $449.4 million and $76.2 million, respectively.

OPERATIONAL RISKS

The nature of the Company’s operations presents inherent risks of loss that could adversely affect its results of operations, financial condition and cash flows.

The Company’s operations in its various reporting segments are subject to inherent hazards and risks such as: fires; natural disasters; explosions; blowouts during well drilling; collapses of wellbore casing or other tubulars; pipeline ruptures; spills; and other hazards and risks that may cause personal injury, death, property damage, environmental damage or business interruption losses. Additionally, the Company’s facilities, machinery, equipment, and technology/software systems may be subject to sabotage. These events, in turn, could lead to governmental investigations, recommendations, claims, fines or penalties. As protection against operational hazards, the Company maintains insurance coverage against some, but not all, potential losses. The Company also seeks, but may be unable, to secure written indemnification agreements with contractors that adequately protect the Company against liability from all of the consequences of the hazards described above. The occurrence of an event not fully insured or indemnified against, the imposition of fines, penalties or mandated programs by governmental authorities, the failure of a contractor to meet its indemnification obligations, or the failure of an insurance company to pay valid claims could result in substantial losses to the Company. In addition, insurance may not be available, or if available may not be adequate, to cover any or all of these risks. It is also possible that insurance premiums or other costs may rise significantly in the future, so as to make such insurance prohibitively expensive.

Hazards and risks faced by the Company, and insurance and indemnification obtained or provided by the Company, may subject the Company to litigation or administrative proceedings from time to time. Such litigation or proceedings could result in substantial monetary judgments, fines or penalties against the Company or be resolved on unfavorable terms, the result of which could have a material adverse effect on the Company’s results of operations, financial condition and cash flows.

Our businesses depend on natural gas gathering, storage, and transmission facilities, which, if unavailable, could adversely affect the Company’s results of operations, financial condition, and cash flows.

Our businesses depend on natural gas gathering, storage, and transmission facilities, including third-party midstream facilities that are not within our control. Our Exploration and Production and Utility segments have entered into long-term agreements with midstream providers for natural gas gathering, storage, and/or transportation services. The disruption or unavailability of the midstream facilities required to provide these services, due to maintenance, mechanical failures, accidents, weather, regulatory requirements and/or other operational hazards, could negatively impact our ability to market and/or deliver our products, especially if such disruption were to last for an extended period of time. In addition, any substantial disruptions to the services provided by our midstream providers could cause us to curtail a significant amount of our production or could impair our ability to deliver natural gas to our utility customers and could have a material adverse effect on the Company’s results of operations, financial condition, and cash flows. Furthermore, as substantially all of our production is transported from the well pad to interconnections with various FERC-regulated pipelines through our affiliated gathering facilities, such a production curtailment could result in significantly reduced throughput on those facilities, adversely affecting revenues and cash flows of our Gathering segment.

The disruption of the Company's information technology and operational technology systems, including third party attempts to breach the Company’s network security, could adversely affect the Company's financial results.

The Company relies on information technology and operational technology systems to process, transmit, and store information, to manage and support a variety of business processes and activities, and to comply with regulatory, legal, and tax requirements. The Company's information technology and operational technology systems, some of which are dependent on services provided by third parties, may be vulnerable to damage, interruption, or shutdown due to any number of causes outside of our control such as catastrophic events, natural disasters, fires, power outages, systems failures, telecommunications failures, and employee error or malfeasance. In addition, the Company's information technology and operational technology systems are subject to attempts by others to gain unauthorized access, or to otherwise introduce malicious software. These attempts might be the result of industrial or other espionage, or actions by hackers seeking to harm the Company, its services or customers. These more sophisticated cyber-related attacks, as well as cybersecurity failures resulting from human error, pose a risk to the security of the Company’s systems and networks and the confidentiality, availability and integrity of the Company’s and its customers’ data. That data may be considered sensitive, confidential, or personal information that is subject to privacy and security laws, regulations and directives. While the Company employs reasonable and appropriate controls to maintain and protect its information technology and operational technology systems, the Company may be vulnerable to material disruptions, material security breaches, lost or corrupted data, programming errors and employee errors and/or malfeasance that could lead to interruptions to the Company's business operations or the unauthorized access, use, disclosure, modification or destruction of sensitive, confidential or personal information. Attempts to breach the Company’s network security may result in disruption of the Company’s business operations and services, delays in production, theft of sensitive and valuable data, damage to our physical systems, and reputational harm. Significant expenditures may be required to remedy system disruptions or breaches, including restoration of customer service and enhancement of information technology and operational technology systems.

The Company seeks to prevent, detect and investigate security incidents, but in some cases the Company might be unaware of an incident or its magnitude and effects. In addition to existing risks, the adoption of new technologies may increase the Company’s exposure to data breaches or the Company’s ability to detect and remediate effects of a breach. The Company has experienced attempts to breach its network security and has received notifications from third-party service providers who have experienced disruptions to services or data breaches where Company data was potentially impacted. Although the scope of such incidents is sometimes unknown, they could prove to be material to the Company. Even though insurance coverage is in place for cyber-related risks, if a material disruption or breach were to occur, the Company’s operations, earnings, cash flows and financial condition could be adversely affected to the extent not fully covered by such insurance.

The amount and timing of actual future natural gas production and the costs of our natural gas production operations are difficult to predict and may vary significantly from estimates, which may reduce the Company’s earnings.

There are many risks in developing natural gas, including numerous uncertainties inherent in estimating quantities of proved natural gas reserves and in projecting future rates of production and timing of development expenditures. The future success of the Company’s Exploration and Production and Gathering segments depends on its ability to develop additional natural gas reserves that are economically recoverable, and its failure to do so may negatively impact the Company’s financial outlook for these businesses. The total and timing of actual future production may vary significantly from reserves and production estimates. The Company’s drilling of development wells can involve significant risks, including those related to timing, success rates, and cost overruns, and these risks can be affected by lease and rig availability, completion crew and related equipment availability, geology, and other factors. Drilling for natural gas can be unprofitable, not only from non-productive wells, but from productive wells that do not produce sufficient revenues to return a profit. Also, title problems, competition and cost to acquire mineral rights, weather conditions, governmental requirements, including completion of environmental impact analyses and compliance with other environmental laws and regulations, and shortages or delays in the delivery of equipment and services can delay drilling operations or result in their cancellation. The cost of drilling, completing, and operating wells is significant and often uncertain, and new wells may not be productive or the Company may not recover all or any portion of its investment. Production can also be delayed or made uneconomic if there is insufficient gathering, processing and transportation capacity available at an economic price to get that production to a location where it can be profitably sold. Without continued successful exploitation or acquisition activities, the Company’s reserves and revenues will decline as a result of its current reserves being depleted by production. The Company cannot make assurances that it will be able to find or acquire additional reserves at acceptable costs.

The Company's ability to access water and opportunities for disposal or recycling produced water can impact drilling and completion operations.

The drilling and hydraulic fracturing process requires significant volumes of water and an ability to recycle or dispose of water produced as a by-product of gas production. Limitations or restrictions on the Company's ability to secure sufficient amounts of water, including disruptions from natural causes (such as drought) or issues with transportation availability and costs, could impact its operations. If the Company is unable to secure adequate water volumes, drilling and completions can be delayed, or it would have to obtain new sources of water at increased costs. Similarly, if the Company experiences limitations or restrictions on its ability to recycle or dispose of its produced water, whether due to environmental regulations, permit requirements, transportation issues or other factors, producing wells may need to be shut-in and new wells may be delayed until such time as adequate recycling or disposal capacity is obtained, which can require significant lead times for permitting and could result in increased costs, delays in the Company's operations and adverse impacts on its cash flow and results of operations.

The physical risks associated with climate change may adversely affect the Company’s operations and financial results.

Climate change could create acute and/or chronic physical risks to the Company’s operations, which may adversely affect financial results. Acute physical risks include more frequent and severe weather events, which may result in adverse physical effects on portions of natural gas infrastructure, and could disrupt the Company’s supply chain and ultimately its operations. Disruption of production activities, as well as natural gas transportation and distribution systems, could result in reduced operational efficiency, and customer service interruption. Severe weather events could also cause physical damage to facilities, all of which could lead to reduced revenues, increased insurance premiums or increased operational costs. To the extent the Company’s regulated businesses are unable to recover those costs, or if the recovery of those costs results in higher rates and reduced demand for Company services, the Company’s future financial results could be adversely impacted. Chronic physical risks include long-term shifts in climate patterns resulting in new storm patterns or chronic increased temperatures, which could impact natural gas demand, and adversely impact the Company's future financial results.

Disputes with collective bargaining units representing the Company’s workforce, and work stoppage (e.g. strike or lockout), could adversely affect the Company’s operations as well as its financial results.

Approximately half of the Company’s active workforce is represented by collective bargaining units in New York and Pennsylvania. These labor agreements are negotiated periodically, and therefore, the Company is subject to the risk that such agreements may not be able to be renewed on reasonably satisfactory terms, on anticipated timelines, or at all. In connection with the negotiation of such collective bargaining agreements, or in future matters involving collective bargaining units representing the Company’s workforce, the Company could experience, among other things, strikes, work stoppages, slowdowns or lockouts, which could cause a disruption of the Company's operations and have a material adverse effect on the Company's results of operations and financial condition.

REGULATORY RISKS

The Company’s need to comply with comprehensive, complex, and the sometimes unpredictable enforcement of government regulations may increase its costs and limit its revenue growth, which may result in reduced earnings.

The Company’s businesses are subject to regulation under a wide variety of federal and state laws, regulations and policies. Existing statutes and regulations, including current tax rates and state prevailing wage rate schedules, may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to the Company or its contractors, which may increase the Company's costs, require refunds to customers or affect its business in ways that the Company cannot predict. Administrative agencies may apply existing laws and regulations in unanticipated, inconsistent or legally unsupportable ways, making it difficult to develop and complete projects, and harming the economic climate generally.

Various aspects of the Company's operations are subject to regulation by a variety of federal and state agencies with respect to permitting and environmental requirements. In some areas, the Company’s operations may also be subject to locally adopted ordinances. Administrative proceedings or increased regulation by these agencies could lead to operational delays or restrictions and increased expense for one or more of the Company’s subsidiaries.

The Company is subject to the jurisdiction of the PHMSA. The PHMSA issues regulations and conducts evaluations, among other things, that set safety standards for pipelines and underground storage facilities. If as a result of these or similar new laws or regulations the Company incurs material compliance costs that it is unable to recover fully through rates or otherwise offset, the Company's financial condition, results of operations, and cash flows could be adversely affected.

The Company is subject to the jurisdiction of the FERC with respect to Supply Corporation, Empire and some transactions performed by other Company subsidiaries. The FERC, among other things, approves the rates that Supply Corporation and Empire may charge to their gas transportation and/or storage customers. Those approved rates also impact the returns that Supply Corporation and Empire may earn on the assets that are dedicated to those operations. Pursuant to the petition of a customer or state commission, or on the FERC's own initiative, the FERC has the authority to investigate whether Supply Corporation's and Empire's rates are still "just and reasonable" as required by the NGA, and if not, to adjust those rates prospectively. If Supply Corporation or Empire is required in a rate proceeding to adjust the rates it charges its gas transportation and/or storage customers, or if either Supply Corporation or Empire is unable to obtain approval for rate increases, particularly when necessary to cover increased costs, Supply Corporation's or Empire's earnings may decrease. In addition, the FERC exercises jurisdiction over the construction and operation of interstate natural gas transmission and storage facilities and also possesses significant penalty authority with respect to violations of the laws and regulations it administers.

The operations of Distribution Corporation are subject to the jurisdiction of the NYPSC, the PaPUC and, with respect to certain transactions, the FERC. The NYPSC and the PaPUC, among other things, approve the rates that Distribution Corporation may charge to its utility customers. Those approved rates also impact the returns that Distribution Corporation may earn on the assets that are dedicated to those operations. If Distribution Corporation is unable to obtain approval from these regulators for the rates it is requesting to charge utility customers, particularly when necessary to cover increased costs, earnings and/or cash flows may decrease.

Environmental regulation significantly affects the Company’s business.

The Company’s business operations are subject to federal, state, and local laws, regulations and agency policies relating to environmental protection including obtaining and complying with permits, leases, approvals, consents and certifications from various governmental and permit authorities. These laws, regulations and policies concern the generation, storage, transportation, disposal, emission or discharge of pollutants, contaminants, hazardous substances and greenhouse gases into the environment, the reporting of such matters, and the general protection of public health, natural resources, wildlife and the environment. For example, currently applicable environmental laws and regulations restrict the types, quantities and concentrations of materials that can be released into the environment in connection with regulated activities, limit or prohibit activities in certain protected areas, and may require the Company to investigate and/or remediate contamination at certain current and former properties regardless of whether such contamination resulted from the Company’s actions or whether such actions were in compliance with applicable laws and regulations at the time they were taken. Moreover, spills or releases of regulated substances or the discovery of currently unknown contamination could expose the Company to material losses, expenditures and environmental, health and safety liabilities. Such liabilities could include penalties, sanctions or claims for damages to persons, property or natural resources brought on behalf of the government or private litigants that could cause the Company to incur substantial costs or uninsured losses.

Costs of compliance and liabilities could negatively affect the Company’s results of operations, financial condition and cash flows. In addition, compliance with environmental laws, regulations or permit conditions could require unexpected capital expenditures at the Company’s facilities, temporarily shut down the Company’s facilities or delay or cause the cancellation of expansion projects or natural gas drilling activities. Because the costs of such compliance are significant, additional regulation could negatively affect the Company’s business.

Increased regulation of exploration and production activities, including hydraulic fracturing, could adversely impact the Company.

Various state legislative and regulatory initiatives regarding the exploration and production business have been proposed or adopted in the northeast United States affecting the Marcellus and Utica Shale gas plays. These initiatives include potential new or updated statutes and regulations governing the drilling, casing, cementing, testing, monitoring and abandonment of wells, the protection of water supplies and restrictions on water use and water rights, hydraulic fracturing operations, increased setback requirements, surface owners’ rights and damage compensation, the spacing of wells, use and disposal of potentially hazardous materials, and environmental and safety issues regarding natural gas pipelines. New permitting fees and/or severance taxes for natural gas production are also possible. Additionally, legislative initiatives in the U.S. Congress and environmental and health studies, proceedings or rule-making initiatives at federal, state or local agencies focused on the hydraulic fracturing process, the use of underground injection control wells for produced water disposal, and related operations could result in operational delays or prohibitions and/or additional permitting, compliance, reporting and disclosure requirements, which could lead to increased operating costs and increased risks of litigation for the Company.

The Company could be adversely affected by the delayed recovery or disallowance of purchased gas costs incurred by the Utility segment.

Tariff rate schedules in each of the Utility segment’s service territories contain purchased natural gas adjustment clauses which permit Distribution Corporation to file with state regulators for rate adjustments to recover increases in the cost of purchased natural gas. Assuming those rate adjustments are granted, increases in the cost of purchased natural gas have no direct impact on profit margins. Distribution Corporation is required to file an accounting reconciliation with the regulators in each of the Utility segment’s service territories regarding the costs of purchased natural gas. Extreme weather events, variations in seasonal weather, and other events disrupting supply and/or demand could cause the Company to experience unforeseeable and unprecedented increases in the costs of purchased natural gas. Prudently incurred natural gas costs could be subject to deferred recovery if regulators determine such costs are detrimental to customers in the short-term. Furthermore, there is a risk of disallowance of full recovery of these costs if regulators determine that Distribution Corporation was imprudent in making its natural gas purchases. Any material delayed recovery or disallowance of purchased natural gas costs could have a material adverse effect on cash flow and earnings.

GENERAL RISKS

The Company’s credit ratings may not reflect all the risks of an investment in its securities.

The Company’s credit ratings are an independent assessment of its ability to pay its obligations. Consequently, real or anticipated changes in the Company’s credit ratings will generally affect the market value of the specific debt instruments that are rated, as well as the market value of the Company’s common stock. The

Company’s credit ratings, however, may not reflect the potential impact on the value of its common stock of risks related to structural, market or other factors discussed in this Form 10-K.

The increasing costs of certain employee and retiree benefits, and the regulatory treatment of certain benefit plan activity, could adversely affect the Company’s results.

The Company’s earnings and cash flow may be impacted by the amount of income or expense it expends or records for employee benefit plans. This is particularly true for pension and other post-retirement benefit plans, which are dependent on actual plan asset returns and factors used to determine the value and current costs of plan benefit obligations. In addition, if medical costs rise at a rate faster than the general inflation rate, the Company might not be able to mitigate the rising costs of medical benefits. Increases to the costs of pension, other post-retirement and medical benefits could have an adverse effect on the Company’s financial results. The Company’s earnings and cash flows may also be impacted by the rate treatment of certain income and expense activity and regulatory asset and liability balances that would be determined in a future rate proceeding.

Significant shareholders or potential shareholders may attempt to effect changes at the Company or acquire control over the Company, which could adversely affect the Company’s results of operations and financial condition.

Shareholders of the Company may from time to time engage in proxy solicitations, advance shareholder proposals or otherwise attempt to effect changes or acquire control over the Company. Campaigns by shareholders to effect changes at publicly traded companies are sometimes led by investors seeking to increase short-term shareholder value through actions such as financial restructuring, increased debt, special dividends, stock repurchases or sales of assets or the entire company. Additionally, activist shareholders may submit proposals to promote an environmental, social, and/or governance position. Responding to proxy contests and other actions by activist shareholders can be costly and time-consuming, disrupting the Company’s operations and diverting the attention of the Company’s Board of Directors and senior management from the pursuit of business strategies. As a result, shareholder campaigns could adversely affect the Company’s results of operations and financial condition.

General Information on Facilities

The net investment of the Company in property, plant and equipment was $7.3 billion at September 30, 2023. The Exploration and Production segment constitutes 35.0% of this investment, and is primarily located in the Appalachian region of the United States. Approximately 52.8% of the Company's investment in net property, plant and equipment was in the Utility and Pipeline and Storage segments, whose operations are located primarily in western and central New York and western Pennsylvania. The Gathering segment constitutes 12.2% of the Company’s investment in net property, plant and equipment, and is located in northwestern and central Pennsylvania. During the past five years, the Company has made significant additions to property, plant and equipment in order to expand its exploration and production and gathering operations in the Appalachian region of the United States and to expand and modernize transmission, storage, and distribution facilities for customers in New York and Pennsylvania. Net property, plant and equipment has increased $2.3 billion, or 46.7%, since September 30, 2018. The five year increase is net of impairments of oil and gas producing properties recorded in 2020 and 2021 ($449 million and $76 million, respectively).

The Exploration and Production segment had a net investment in property, plant and equipment of $2.6 billion at September 30, 2023 consisting primarily of capitalized costs relating to oil and gas producing activities, the components of which are disclosed in Item 8, Note N — Supplementary Information for Oil and Gas Producing Activities.

The Pipeline and Storage segment had a net investment of $2.1 billion in property, plant and equipment at September 30, 2023. Transmission pipeline represents 35% of this segment’s total net investment and includes 2,246 miles of pipeline utilized to move large volumes of gas throughout its service area. Storage facilities represent 13% of this segment’s total net investment and consist of 385 miles of pipeline, as well as 29 storage fields operating at a combined working gas level of 77.2 Bcf, three of which are jointly owned and operated with other interstate gas pipeline companies. Net investment in storage facilities includes $82.2 million of gas stored underground-noncurrent, representing the cost of the gas utilized to maintain pressure levels for normal operating purposes as well as gas maintained for system balancing and other purposes, including that needed for no-notice transportation service. The Pipeline and Storage segment has 31 compressor stations with 260,008 installed horsepower that represent 31% of this segment’s total net investment in property, plant and equipment.

The Pipeline and Storage segment's facilities provided the capacity to meet Supply Corporation’s 2023 peak day sendout for transportation service of 2,360 MMcf, which occurred on February 3, 2023. Withdrawals from storage of 505 MMcf provided approximately 21% of the requirements on that day.

The Gathering segment had a net investment of $0.9 billion in property, plant and equipment at September 30, 2023. Gathering lines and related compressor stations represent substantially all of this segment’s total net investment, including 376 miles of pipelines utilized to move Appalachian production (including Marcellus and Utica shales) to various transmission pipeline receipt points. The Gathering segment has 24 compressor stations with 124,256 installed horsepower.

The Utility segment had a net investment in property, plant and equipment of $1.7 billion at September 30, 2023. The net investment in its gas distribution network (including 15,052 miles of distribution pipeline) and its service connections to customers represent approximately 49% and 32%, respectively, of the Utility segment’s net investment in property, plant and equipment at September 30, 2023.

Company maps are included in Exhibit 99.2 of this Form 10-K and are incorporated herein by reference.

Exploration and Production Activities

The Company is engaged in the exploration for and the development of natural gas reserves in the Appalachian region of the United States. The Company's development activities in the Appalachian region are focused primarily in the Marcellus and Utica shales. Further discussion of oil and gas producing activities is included in Item 8, Note N — Supplementary Information for Oil and Gas Producing Activities. Note N sets forth proved developed and undeveloped reserve information for Seneca. The September 30, 2023, 2022 and 2021 reserves shown in Note N are valued using 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. The reserves were estimated by Seneca’s petroleum engineers and were audited by independent petroleum engineers from Netherland, Sewell & Associates, Inc. Note N discusses the qualifications of the Company's petroleum engineers, internal controls over the reserve estimation process and audit of the reserve estimates and changes in proved developed and undeveloped oil and natural gas reserves year over year.

Seneca's proved developed and undeveloped natural gas reserves increased from 4,171 Bcf at September 30, 2022 to 4,535 Bcf at September 30, 2023. This increase is attributed to extensions and discoveries of 670 Bcf, purchases of minerals in place of 34 Bcf, and revisions of previous estimates of 32 Bcf, partially offset by production of 372 Bcf. Upward revisions of 94 Bcf are mainly attributed to positive performance improvements and adding back one PUD location. The additions and upward revisions were partially offset by downward revisions of 62 Bcf from the removal of seven PUD locations related to pad layout changes and price-related revisions. The Company has no near term plans to develop the reserves at these PUD locations.

Seneca’s proved developed and undeveloped oil reserves decreased from 250 Mbbl at September 30, 2022 to 216 Mbbl at September 30, 2023. The decrease was attributed to current year production of 30 Mbbl and downward revisions of previous estimates of 4 Mbbl.

On a Bcfe basis, Seneca’s proved developed and undeveloped reserves increased from 4,172 Bcfe at September 30, 2022 to 4,536 Bcfe at September 30, 2023. This increase is attributed to extensions and discoveries of 670 Bcfe, purchases of minerals in place of 34 Bcfe and net upward revisions of previous estimates of 32 Bcfe, partially offset by production of 372 Bcfe.

Seneca's proved developed and undeveloped natural gas reserves increased from 3,723 Bcf at September 30, 2021 to 4,171 Bcf at September 30, 2022. This increase was attributed to extensions and discoveries of 838 Bcf and revisions of previous estimates of 3 Bcf, partially offset by production of 343 Bcf. Upward revisions included 3 Bcf of price-related revisions and 13 Bcf of revisions related to positive performance improvements including reduced operating expenses. The additions and upward revisions were partially offset by divestures of 50 Bcf as well as downward revisions of 13 Bcf from the removal of one PUD location related to pad layout changes. The Company has no near term plans to develop the reserves at this PUD location.

Seneca’s proved developed and undeveloped oil reserves decreased from 21,537 Mbbl at September 30, 2021 to 250 Mbbl at September 30, 2022. The decrease of 21,287 Mbbl was attributed to production of 1,604 Mbbl and the sale of Seneca's West Coast region (i.e., California) assets of 20,766 Mbbl. These decreases were partially offset by positive performance revisions of 787 Mbbl and extensions and discoveries of 296 Mbbl.

On a Bcfe basis, Seneca’s proved developed and undeveloped reserves increased from 3,853 Bcfe at September 30, 2021 to 4,172 Bcfe at September 30, 2022. This increase was attributed to extensions and discoveries of 839 Bcfe and upward revisions of previous estimates of 8 Bcfe, partially offset by production of 353 Bcfe and divestures, primarily from the sale of the West Coast region (i.e., California) assets, of 175 Bcfe.

At September 30, 2023, the Company’s Exploration and Production segment had delivery commitments for natural gas production of 2,147 Bcf. The Company expects to meet those commitments through the future production of reserves that are currently classified as proved reserves and future extensions and discoveries.

The following is a summary of certain oil and gas information taken from Seneca’s records.

Production

(1) Average sales prices per Mcf of gas reflect sales of gas in the Marcellus and Utica Shale fields. The Marcellus Shale fields (which exceed 15% of total reserves at September 30, 2023, 2022 and 2021) contributed 521 MMcfe, 574 MMcfe and 597 MMcfe of daily production in 2023, 2022 and 2021, respectively. The average lifting costs (per Mcfe) were $0.73 in 2023, $0.71 in 2022 and $0.70 in 2021. The Utica Shale fields (which exceed 15% of total reserves at September 30, 2023, 2022 and 2021) contributed 495 MMcfe, 357 MMcfe and 255 MMcfe of daily production in 2023, 2022 and 2021, respectively. The average lifting costs (per Mcfe) were $0.62 in 2023, $0.63 in 2022 and $0.62 in 2021.

(2) West Coast region properties were sold at June 30, 2022. Information for the year ended September 30, 2023 is not applicable (N/A) as a result of the sale.

Productive Wells

Developed and Undeveloped Acreage

(1) Of the 1,321,954 Total Developed and Undeveloped Net Acreage in the Appalachian region as of September 30, 2023, there are a total of 1,250,077 net acres in Pennsylvania. Of the 1,250,077 total net acres in Pennsylvania, shale development in the Marcellus, Utica or Geneseo shales has occurred on approximately 134,414 net acres, or 11% of Seneca’s total net acres in Pennsylvania. Developed Acreage in the table reflects previous development activities in the Upper Devonian formation, but does not include the potential for development beneath this formation in areas of previous development, which includes the Marcellus, Utica and Geneseo shales.

As of September 30, 2023, the aggregate amounts of gross undeveloped acreage expiring under lease in the next three years and thereafter are as follows: 20,858 acres in 2024 (19,108 net acres), 11,176 acres in 2025 (10,180 net acres), 15,389 acres in 2026 (14,219 net acres) and 211,719 acres thereafter (193,090 net acres). The remaining 469,247 gross acres (435,079 net acres) represent non-expiring oil and gas rights owned by the Company. Of the acreage that is currently scheduled to expire in 2024, 2025 and 2026, Seneca has 352.2 Bcf of associated proved undeveloped gas reserves. As a part of its management approved development plan, Seneca generally commences development of these reserves prior to the expiration of the leases and/or proactively extends/renews these leases.

Drilling Activity

(1) Fiscal 2023, 2022 and 2021 Appalachian region dry wells include 0.5, 2.5 and 2 net wells, respectively, drilled prior to 2013 that were never completed under a joint venture in which the Company was the nonoperator. The Company became the operator of the properties in 2017 and plugged and abandoned the wells in 2023, 2022 and 2021 after the Company determined it would not continue development activities.

Present Activities

(1) Includes wells awaiting completion.

For a discussion of various environmental and other matters, refer to Part II, Item 7, MD&A and Item 8 at Note L — Commitments and Contingencies.

For a discussion of certain rate matters involving the NYPSC, refer to Part II, Item 7, MD&A of this report under the heading "Other Matters - Rate Matters."

OVERVIEW

The Company is a diversified energy company engaged principally in the production, gathering, transportation, storage and distribution of natural gas. The Company operates an integrated business, with assets centered in western New York and Pennsylvania, being utilized for, and benefiting from, the production and transportation of natural gas from the Appalachian Basin. Current development activities are focused primarily in the Marcellus and Utica shales. The common geographic footprint of the Company’s subsidiaries enables them to share management, labor, facilities and support services across various businesses and pursue coordinated projects designed to produce and transport natural gas from the Appalachian Basin to markets in the eastern United States and Canada. The Company's efforts in this regard are not limited to affiliated projects. The Company has also been designing and building pipeline projects for the transportation of natural gas for non-affiliated natural gas customers in the Appalachian Basin. The Company reports financial results for four business segments: Exploration and Production, Pipeline and Storage, Gathering, and Utility.

Corporate Responsibility

The Board of Directors and management recognize that the long-term interests of stockholders are served by considering the interests of customers, employees and the communities in which the Company operates. The Board retains risk oversight and general oversight of corporate responsibility, including environmental, social and governance (“ESG”) concerns, and any related health and safety issues that might arise from the Company’s operations. The Board’s Nominating/Corporate Governance Committee oversees and provides guidance concerning the Company’s practices and reporting with respect to corporate responsibility and ESG factors that are of significance to the Company and its stakeholders, and may also make recommendations to the Board regarding ESG initiatives and strategies, including the Company’s progress on integrating ESG factors into business strategy and decision-making.

Part of the Board and management’s strategic and capital spending decision process includes identifying and assessing climate-related risks and opportunities. Management reports quarterly to the Board on critical and potentially emerging risks, including climate-related risks, as part of the Enterprise Risk Management process. Since the Company operates an integrated business with assets being utilized for, and benefiting from, the production, transportation and consumption of natural gas, the Board and management consider physical and transitional climate risks, including policy and legal risks, technological developments, shifts in market conditions, including future natural gas usage, and reputational risks, and the impact of those risks on the Company’s business. The Company reviews and considers adjustments to its approach to capital investment in response to these risks and developments, with its long-term, returns-focused approach.

The Company recognizes the important role of ongoing system modernization and efficiency in reducing greenhouse gas emissions and remains focused on reducing the Company’s carbon footprint, with these efforts positioning natural gas, and the Company’s related infrastructure, to remain an important part of the energy complex. In 2021, the Company set methane intensity reduction targets at each of its businesses, an absolute greenhouse gas emissions reduction target for the consolidated Company, and greenhouse gas reduction targets associated with the Company’s utility delivery system. In 2022, the Company began measuring progress against these reduction targets. The Company also incorporated short-term and long-term executive compensation goals designed to incentivize and reward performance if reduction targets are met or exceeded. The Company's ability to estimate accurately the time, costs and resources necessary to meet these emissions reduction targets may change as environmental exposures and opportunities change, technology advances, and legislative and regulatory updates are issued.

Fiscal 2023 Highlights

This Item 7, MD&A, provides information concerning:

1. The critical accounting estimates of the Company;

2. Changes in revenues and earnings of the Company under the heading, “Results of Operations;”

3. Operating, investing and financing cash flows under the heading “Capital Resources and Liquidity” and;

4. Other Matters, including: (a) 2023 and projected 2024 funding for the Company’s pension and other post-retirement benefits; (b) disclosures and tables concerning market risk sensitive instruments; (c) rate matters in the Company’s New York, Pennsylvania and FERC-regulated jurisdictions; (d) environmental matters; and (e) effects of inflation.

The information in MD&A should be read in conjunction with the Company’s financial statements in Item 8 of this report, which includes a comparison of our Results of Operations and Capital Resources and Liquidity for fiscal 2023 and fiscal 2022. For a discussion of the Company's earnings, refer to the Results of Operations section below. A discussion of changes in the Company’s results of operations from fiscal 2021 to fiscal 2022 has been omitted from this Form 10-K, but may be found in Item 7, MD&A, of the Company’s Form 10-K for the fiscal year ended September 30, 2022, filed with the SEC on November 18, 2022.

The Company's Exploration and Production segment continues to grow, as evidenced by a 9% growth in proved reserves from the prior year to a total of 4,536 Bcfe at September 30, 2023. Production increased 19.9 Bcfe during the fiscal year ended September 30, 2023 to a total of 372.5 Bcfe, and is expected to increase again in fiscal 2024.

On June 1, 2023, the Company completed its acquisition of certain upstream assets located primarily in Tioga County, Pennsylvania from SWN Production Company, LLC ("SWN") for total consideration of $124.8 million. As part of the transaction, the Company acquired approximately 34,000 net acres in an area that is contiguous with existing Company-owned upstream assets. This transaction was accounted for as an asset acquisition and, as such, the purchase price was allocated to property, plant and equipment.

The Company has continued to pursue development projects to expand its Pipeline and Storage segment. One project on Supply Corporation's system, referred to as the Tioga Pathway Project, would allow for the transportation of 190,000 Dth per day of shale gas supplies from a new interconnection in northwest Tioga County, Pennsylvania to an existing Supply Corporation interconnection with Tennessee Gas Pipeline Company, LLC at Ellisburg and a new virtual delivery point into an existing Transcontinental Gas Pipe Line Company, LLC’s (“Transco”) capacity lease, providing access to Mid-Atlantic markets. The Tioga Pathway Project has a target in-service date in late calendar 2026 and a preliminary cost estimate of approximately $90 million. The Tioga Pathway Project is discussed in more detail in the Capital Resources and Liquidity section that follows.

From a rate perspective, Distribution Corporation, in its Pennsylvania jurisdiction, reached a settlement with the parties to its rate case proceeding. On June 15, 2023, the PaPUC issued an order adopting the settlement in full. The settlement authorized an increase in Distribution Corporation's annual base rate operating revenues of $23 million that became effective August 1, 2023. Distribution Corporation also filed a rate case proceeding with the NYPSC in its New York jurisdiction on October 31, 2023 seeking an increase of $88.8 million in its total annual operating revenues for the projected rate year ending September 30, 2025, with a proposed effective date of October 1, 2024. In addition, Supply Corporation filed a NGA Section 4 rate case at FERC on July 31, 2023. For further discussion of Distribution Corporation and Supply Corporation rate matters, refer to the Rate Matters section below.

From a financing perspective, on June 30, 2022, the Company entered into a 364-Day Credit Agreement (the "364-Day Credit Agreement") with a syndicate of five banks, all of which are also lenders under a Credit Agreement (as amended from time to time, the "Credit Agreement"). The 364-Day Credit Agreement provided 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. In March 2023, the Company utilized short-term borrowings and cash on hand to redeem the remaining long-term debt that had maturity dates in March 2023, which included $350.0 million of 3.75% notes and $49.0 million of 7.395% notes.

On May 18, 2023, the Company issued $300.0 million of 5.50% notes due October 1, 2026. The proceeds of this debt issuance were used for general corporate purposes, including to repay all indebtedness under the $250.0 million unsecured committed delayed draw term loan under the 364-Day Credit Agreement mentioned above.

The Company expects to use cash on hand, cash from operations, and short-term and long-term borrowings, as needed, to meet its financing needs for fiscal 2024. The Company continues to evaluate these financing needs and options to meet them. Given the current economic conditions, which include continued inflationary pressures and rising interest rates, the cost and/or availability of capital may be impacted, but the Company continues to expect to meet its financing needs as discussed above.

In early 2023, turmoil with certain financial institutions created uncertainty in the economy. While the Company was not directly impacted, it continues to closely monitor any potential future impacts on the business. The Company has a diverse group of twelve banks that participate in its multi-year credit facility. All of these banks have solid investment grade credit ratings. Additionally, the Company regularly reviews the credit quality of its hedging counterparties, those that provide credit support for customers, and any other material counterparties, and has not identified any material risks as a result of the current economic uncertainty.

CRITICAL ACCOUNTING ESTIMATES

The Company has prepared its consolidated financial statements in conformity with GAAP. The preparation of these financial statements 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. In the event estimates or assumptions prove to be different from actual results, adjustments are made in subsequent periods to reflect more current information. The following is a summary of the Company’s most critical accounting estimates, which are defined as those estimates whereby judgments or uncertainties could affect the application of accounting policies and materially different amounts could be reported under different conditions or using different assumptions. For a complete discussion of the Company’s significant accounting policies, refer to Item 8 at Note A — Summary of Significant Accounting Policies.

Oil and Gas Exploration and Development Costs. In the Company's Exploration and Production segment, gas and oil property acquisition, exploration and development costs are capitalized under the full cost method of accounting, with natural gas properties in the Appalachian region being the primary component of these capitalized costs after the June 30, 2022 sale of the Company's California oil and natural gas properties. That sale is discussed in more detail in Item 8 at Note B — Asset Acquisitions and Divestitures. Under this accounting 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.

Proved reserves are estimated quantities of reserves that, based on geologic and engineering data, appear with reasonable certainty to be producible under existing economic and operating conditions. Such estimates of proved reserves are inherently imprecise and may be subject to substantial revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. The estimates involved in determining proved reserves are critical accounting estimates because they serve as the basis over which capitalized costs are depleted under the full cost method of accounting (on a units-of-production basis). Unproved properties are excluded from the depletion calculation until proved reserves are found or it is determined that the unproved properties are impaired. 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.

In addition to depletion under the units-of-production method, proved reserves are a major component in the SEC full cost ceiling test. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. 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 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 (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 estimates of future production and future expenditures are based on internal budgets that reflect planned production from current wells and expenditures necessary to sustain such future production. The amount of the ceiling can fluctuate significantly from period to period because of additions to or subtractions from proved reserves and significant fluctuations in natural gas prices. The ceiling is then compared to the capitalized cost of oil and gas properties less accumulated depletion and related deferred income taxes. If the capitalized costs of oil and gas properties less accumulated depletion and related deferred taxes exceeds the ceiling at the end of any fiscal quarter, a non-cash impairment charge must be recorded to write down the book value of the reserves to their present value. This non-cash impairment cannot be reversed at a later date if the ceiling increases. It should also be noted that a non-cash impairment to write down the book value of the reserves to their present value in any given period causes a reduction in future depletion expense. At September 30, 2023, the ceiling exceeded the book value of the oil and gas properties by approximately $794.7 million. The 12-month average of the first day of the month price for natural gas for each month during 2023, based on the quoted Henry Hub spot price for natural gas, was $3.42 per MMBtu. (Note — because actual pricing of the Company’s producing properties vary depending on their location and hedging, the prices used to calculate the ceiling may differ from the Henry Hub price, which is only indicative of 12-month average prices for 2023. Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.) In regard to the sensitivity of the ceiling test calculation to commodity price changes, if natural gas prices were $0.25 per MMBtu lower than the average prices used at September 30, 2023 in the ceiling test calculation, the ceiling would have exceeded the book value of the Company's oil and gas properties by approximately $442.9 million (after-tax), which would not have resulted in an impairment charge. This calculated amount is based solely on price changes and does not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates.

It is difficult to predict what factors could lead to future non-cash impairments under the SEC’s full cost ceiling test. As discussed above, fluctuations in or subtractions from proved reserves, increases in development costs for undeveloped reserves and significant fluctuations in natural gas prices have an impact on the amount of the ceiling at any point in time.

As discussed above, the full cost method of accounting provides a ceiling to the amount of costs that can be capitalized in the full cost pool. In accordance with current authoritative guidance, the future cash outflows associated with plugging and abandoning wells are excluded from the computation of the present value of estimated future net revenues for purposes of the full cost ceiling calculation.

Regulation. The Company is subject to regulation by certain state and federal authorities. The Company, in its Utility and Pipeline and Storage segments, has accounting policies which conform to the FASB authoritative guidance regarding accounting for certain types of regulations, and which are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting principles for certain types of rate-regulated activities provides that certain actual or anticipated costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, the

Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the balance sheet and included in the Consolidated Statement of Income for the period in which the discontinuance of regulatory accounting treatment occurs. Such amounts would be classified as an extraordinary item. For further discussion of the Company’s regulatory assets and liabilities, refer to Item 8 at Note F — Regulatory Matters.

RESULTS OF OPERATIONS

The Company's earnings were $476.9 million in 2023 compared with earnings of $566.0 million in 2022. The decrease in earnings of $89.1 million was a result of lower earnings in all reportable segments, as well as losses in the Corporate and All Other categories. In the discussion that follows, all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted. Earnings were impacted by the following events in 2022:

2022 Events

• The reversal of a deferred tax valuation allowance of $24.9 million recorded in the Exploration and Production and Gathering segments, which increased earnings in 2022.
• A $28.4 million remeasurement of accumulated deferred income taxes, primarily in the Exploration and Production and Gathering segments, related to a reduction in the Pennsylvania state corporate income tax rate that was signed into law in July 2022, which increased earnings in 2022.
• A gain recognized on the sale of Seneca's California assets of $12.7 million ($9.5 million after-tax) recorded during 2022 in the Exploration and Production segment related to a portion of the sale price that was applied to assets that were not subject to the full cost method of accounting.
• A loss of $44.6 million ($33.3 million after-tax) recorded during 2022 in the Exploration and Production segment related to the termination of this segment's remaining crude oil derivative contracts as a result of the sale of Seneca's California assets.
• Transaction and severance costs of $9.7 million ($7.2 million after-tax) incurred during 2022 in the Exploration and Production segment related to the sale of Seneca's California assets.
• The reduction of an OPEB regulatory liability that increased earnings by $18.5 million ($14.6 million after-tax) recorded during 2022 in the Utility segment in accordance with a regulatory proceeding in Distribution Corporation's Pennsylvania service territory.

Earnings (Loss) by Segment

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EXPLORATION AND PRODUCTION

Revenues

Exploration and Production Operating Revenues

Production

Average Prices

(1) Oil revenue and weighted average oil price after hedging for the year ended September 30, 2022 excludes a loss on discontinuance of crude oil cash flow hedges of $44.6 million. This loss is presented in other revenue in the table above.

(2) Prices for the year ended September 30, 2023 are not applicable (N/A) as a result of the sale of Seneca's West Coast assets in June 2022.

(3) Refer to further discussion of hedging activities below under “Market Risk Sensitive Instruments” and in Note J — Financial Instruments in Item 8 of this report.

Operating revenues for the Exploration and Production segment decreased $52.0 million in 2023 as compared with 2022. Gas production revenue after hedging increased $18.4 million primarily due to a 29.4 Bcf increase in gas production offset by a $0.16 per Mcf decrease in the weighted average realized price of gas after hedging. The increase in gas production was largely due to new Marcellus and Utica wells in the Appalachian region. Oil production revenue after hedging decreased $111.3 million mainly attributable to the sale of California assets at June 30, 2022. In addition, other revenue increased $43.3 million and plant revenue decreased $2.3 million. The increase in other revenue was primarily attributable to the non-recurrence of a loss on the discontinuance of crude oil cash flow hedges as a result of the sale of California assets combined with the non-recurrence of royalty shut-in payments made in 2022 in accordance with lease agreements. These increases to other revenue were partially offset by decreases to temporary capacity release revenue and a decrease in operating revenue from this segment's water treatment plants. Finally, the decrease in gas processing plant revenues was mainly attributable to the sale of California assets combined with declining gas pricing.

Refer to further discussion of derivative financial instruments in the “Market Risk Sensitive Instruments” section that follows. Refer to the tables above for production and price information.

The Exploration and Production segment’s earnings for 2023 were $232.3 million, a decrease of $73.8 million when compared with earnings of $306.1 million for 2022. The sale of California assets on June 30, 2022 was a large factor in the earnings variance year over year. As a result of the sale, 2023 earnings decreased due to lower oil production ($88.1 million) and the non-recurrence of a gain that was recognized on the sale of Seneca’s California non-full cost pool assets ($9.5 million). However, these factors were partially offset by the non-recurrence of a 2022 loss related to the discontinuance of its crude oil cash flow hedges ($33.3 million) and 2022 transaction and severance costs associated with the sale ($7.2 million). There was also a lower unrealized loss recognized in 2023 ($0.7 million) on contingent consideration received as part of the California asset sale as compared to the unrealized loss that was recognized in 2022 ($3.2 million) on that contingent consideration. Other factors impacted by the sale included lower lease operating and transportation expenses ($24.0 million), lower other operating expenses ($11.1 million), and lower other taxes ($6.0 million). Excluding the impact of the California sale, lease operating and transportation costs in the Appalachian region increased year over year. Other operating costs were also impacted by the non-recurrence of abandonment costs recognized in 2022 for certain offshore Gulf of Mexico wells that were formerly owned by Seneca, and other taxes was also impacted by lower Impact Fees in the Appalachain region. Aside from the earnings impact of these items, the earnings decrease reflected lower natural gas prices after hedging ($48.4 million), lower other revenue ($1.1 million) and lower gas processing plant revenue ($1.8 million), all of which are discussed above. Other factors that decreased earnings included higher depletion expense ($26.1 million), higher interest expense ($0.7 million) and higher income tax expense ($3.4 million). In 2022, the Exploration and Production segment reversed a valuation allowance ($28.6 million) on deferred tax assets related to certain state net operating loss and credit carryforwards as these deferred tax assets are now expected to be realized in the future. The Exploration and Production segment also recorded an income tax benefit ($16.2 million) in 2022 from the remeasurement of deferred income taxes related to a state corporate income tax rate reduction in Pennsylvania that was signed into law in July 2022. The law reduces the Pennsylvania corporate income tax rate to 8.99% for fiscal 2024, and starting with fiscal 2025, the rate is further reduced by 0.5% annually until it reaches 4.99% for fiscal 2032. Partially offsetting these items, the Exploration and Production segment had higher natural gas production ($62.9 million), and higher other income ($2.7 million).

The increase in depletion expense was primarily due to the increase in production, combined with a $0.06 per Mcfe increase in the depletion rate. The year over year increase in the depletion rate was mainly driven by higher capitalized costs and an increase in future development costs related to proved undeveloped wells. The increase in interest expense can largely be attributed to higher average interest rates on short-term and long-term borrowings offset partially by lower intercompany long-term debt balances. The increase in income tax expense was primarily driven by a prior-year benefit realized from the Enhanced Oil Recovery tax credit, which did not recur in the current year as a result of the sale of the California assets. The increase in other income was attributable to higher interest income, as well as non-service pension and post-retirement income in 2023 compared to non-service pension and post-retirement benefit costs in 2022.

PIPELINE AND STORAGE

Revenues

Pipeline and Storage Operating Revenues

Pipeline and Storage Throughput — (MMcf)

2023 Compared with 2022

Operating revenues for the Pipeline and Storage segment increased $2.1 million in 2023 as compared with 2022. The increase in operating revenues was primarily due to an increase in transportation revenues of $1.3 million, an increase in storage revenues of $0.4 million and an increase in other revenues of $0.5 million. The increase in transportation revenues was primarily attributable to new demand charges for transportation service from Supply Corporation's FM100 Project, which was placed into service in December 2021. The increase from the FM100 Project includes the impact of a negotiated revenue step-up to Period 2 Rates that went into effect April 1, 2022, as specified in Supply Corporation's 2020 rate case settlement. An increase in short-term contracts also contributed to the increase in transportation revenues. These increases were partially offset by a decline in revenues associated with miscellaneous contract expirations and revisions. The increase in other revenues primarily reflects proceeds received during the quarter ended September 30, 2023 as a result of a contract buyout.

Transportation volume increased by 22.6 Bcf in 2023 as compared with 2022, primarily due to an increase in short-term contracts, as well as an increase in volume from the FM100 Project. These increases were partially offset by certain contract expirations during fiscal 2023. Volume fluctuations, other than those caused by the addition or termination of contracts, generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.

The majority of Supply Corporation's and Empire's transportation and storage contracts allow either party to terminate the contract upon six or twelve months' notice effective at the end of the primary term and include "evergreen" language that allows for annual term extension(s). The Pipeline and Storage segment's contracted transportation and storage capacity with both affiliated and unaffiliated shippers is expected to remain relatively constant in fiscal 2024.

The Pipeline and Storage segment’s earnings in 2023 were $100.5 million, a decrease of $2.1 million when compared with earnings of $102.6 million in 2022. The decrease in earnings was primarily due to an increase in operating expenses ($5.2 million) and an increase in depreciation expense ($2.5 million). The increase in operating expenses was primarily due to higher personnel costs, higher pipeline integrity costs and an increase in compressor maintenance costs. The increase in depreciation expense was primarily due to incremental depreciation from the FM100 Project. These earnings decreases were partially offset by the impact of higher operating revenues ($1.7 million), as discussed above, combined with higher other income ($3.6 million). The increase in other income is primarily due to a higher weighted average interest rate on intercompany short-term notes receivables along with higher non-service pension and post-retirement benefit income. This was partially offset by a decrease in allowance for funds used during construction (equity component) related to the construction of the FM100 Project along with an annual adjustment that was recorded during the current fiscal year.

GATHERING

Revenues

Gathering Operating Revenues

Gathering Volume — (MMcf)

2023 Compared with 2022

Operating revenues for the Gathering segment increased $15.5 million in 2023 as compared with 2022, which was driven primarily by a 34.0 Bcf increase in gathered volume. Gathered volume on the Tioga and Clermont gathering systems increased 36.3 Bcf and 7.1 Bcf, respectively, partially offset by a decrease of 9.4 Bcf on the Trout Run gathering system. The net increase in gathered volume can be attributed to the increase in gross natural gas production in the Appalachian region by producers connected to the aforementioned gathering systems. All references to the Tioga gathering system in this operating revenues discussion and the earnings discussion that follows include the revenues, volume and earnings of the gathering system owned by NFG Midstream Covington, LLC (Covington), which includes the gathering system previously owned by NFG Midstream Wellsboro, LLC (Wellsboro). Wellsboro was merged into Covington effective August 31, 2023. The merger of Wellsboro into Covington reflects the completion of a pipeline that connects the two systems.

The Gathering segment’s earnings in 2023 were $99.7 million, a decrease of $1.4 million when compared with earnings of $101.1 million in 2022. Income taxes were a significant factor in the year over year variation. First, earnings were negatively impacted by the non-recurrence of an income tax benefit ($11.9 million) during the quarter ended September 30, 2022 from the remeasurement of deferred income taxes related to a state corporate income tax rate reduction in Pennsylvania that was signed into law in July 2022 (as discussed above, in the Exploration and Production segment). This segment also experienced an increase in income tax expense ($1.0 million) due to higher state income tax expense. Partially offsetting these factors, earnings benefited from the non-recurrence of deferred income tax expense ($3.7 million) recognized during the quarter ended

September 30, 2022 as an offset to the Exploration and Production segment's reversal of the deferred tax asset valuation allowance. This offset is a result of the Gathering and Exploration and Production segments' subsidiaries filing a combined state tax return. In addition to these income tax variations, earnings decreased due to higher operating expenses ($4.9 million) and higher depreciation expense ($1.4 million). The increase in operating expenses was largely attributable to higher outside service costs associated with preventative maintenance overhauls on the Clermont, Tioga and Trout Run gathering systems, higher leased compression expense on the Trout Run and Tioga gathering systems and higher labor-related costs across all of the gathering systems. The increase in depreciation expense was largely due to higher plant balances associated with the Tioga and Clermont gathering systems. These earnings decreases were partially offset by the impact of higher gathering revenues ($12.2 million) driven by the increase in gathered volume (discussed above). Additionally, earnings increased due to lower interest expense ($1.2 million) and higher other income ($0.6 million). The decrease in interest expense was primarily due to higher capitalized interest and lower interest on intercompany long-term borrowings associated with the Company's redemption of $500.0 million of 3.75% notes during 2023. The increase in other income is primarily due to lower non-service pension and post-retirement benefit expenses.

UTILITY

Revenues

Utility Operating Revenues

Utility Throughput — million cubic feet (MMcf)

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Degree Days

(1) Percents compare actual degree days to normal degree days and actual degree days to actual prior year degree days.

(2) Normal degree days changed from the NOAA 30-year degree days to NOAA 15-year degree days with the implementation of new base rates in Pennsylvania in August 2023.

Operating revenues for the Utility segment increased $44.1 million in 2023 compared with 2022. The increase resulted from a $47.5 million increase in retail gas sales revenue and a $4.4 million increase in other revenues, which were partially offset by a $7.8 million decrease in transportation revenue. The increase in retail gas sales revenue was primarily due to an increase in the cost of gas sold (per Mcf), partially offset by a 2.9 Bcf decrease in throughput due to warmer weather during the winter months and a decrease in base rates. The decrease in base rates is related to a tariff filing approved by the NYPSC, which created a surcredit that temporarily eliminates pension and OPEB cost recovery from base rates effective October 1, 2022. Additional details related to the regulatory proceeding are discussed in Item 8 at Note F — Regulatory Matters. The increase in other revenues was due to an increase in capacity release revenues and a smaller estimated refund provision from the income tax benefits resulting from the 2017 Tax Reform Act. The decrease in transportation revenue resulted from a 3.0 Bcf decrease in throughput due to warmer weather and the decrease in base rates, as previously mentioned. The decreases in gas retail sales revenue and transportation revenue were partially offset by an increase in revenues earned under the system modernization and system improvement tracker mechanisms in Distribution Corporation's New York jurisdiction, which allow for the recovery of investments in leak prone pipe replacement.

Purchased Gas

The cost of purchased gas is one of the Company’s largest operating expenses. Annual variations in purchased gas costs are attributed directly to changes in gas sales volume, the price of gas purchased and the operation of purchased gas adjustment clauses. Distribution Corporation recorded $548.2 million and $498.0 million of Purchased Gas expense during 2023 and 2022, respectively. Under its purchased gas adjustment clauses in New York and Pennsylvania, Distribution Corporation does not profit from fluctuations in gas costs. Purchased Gas expense recorded on the consolidated income statement matches the revenues collected from customers, a component of Operating Revenues on the consolidated income statement. Under mechanisms approved by the NYPSC in New York and the PaPUC in Pennsylvania, any difference between actual purchased gas costs and what has been collected from the customer is deferred on the consolidated balance sheet as either an asset, Unrecovered Purchased Gas Costs, or a liability, Amounts Payable to Customers. These deferrals are subsequently collected from the customer or passed back to the customer, subject to review by the NYPSC and the PaPUC. Absent disallowance of full recovery of Distribution Corporation’s purchased gas costs, such costs do not impact the profitability of the Company. Purchased gas costs impact cash flow from operations due to the timing of recovery of such costs versus the actual purchased gas costs incurred during a particular period. Distribution Corporation’s purchased gas adjustment clauses seek to mitigate this impact by adjusting revenues on either a quarterly or monthly basis.

Distribution Corporation contracts for firm long-term transportation and storage capacity services with rights-of-first-refusal from ten upstream pipeline companies including Supply Corporation for transportation and storage services and Empire, for transportation services. Distribution Corporation contracts for firm spot and term gas supplies with various producers, marketers and two local distribution companies to meet its gas purchase requirements. Additional discussion of the Utility segment’s gas purchases appears under the heading “Sources and Availability of Raw Materials” in Item 1.

The Utility segment’s earnings in 2023 were $48.4 million, a decrease of $20.5 million when compared with earnings of $68.9 million in 2022. The decrease in earnings was due in part to the impact of a proceeding in the Utility's Pennsylvania service territory during the quarter ended March 31, 2022 that allowed for a favorable one-time adjustment of $14.6 million to recognize the cumulative amount of OPEB income, previously deferred as a regulatory liability in that jurisdiction, which did not recur in 2023. In addition to the non-recurrence of this transaction, there was a decrease in OPEB income ($2.4 million) in the Utility's Pennsylvania service territory.

The earnings impact of the reduction in the New York jurisdiction's base rates in 2023 resulting from the NYPSC tariff filing related to pension and OPEB costs discussed above ($12.0 million), combined with an increase in operating costs ($2.0 million) associated with the elimination of fringe benefit credits being applied to service and non-service pension and OPEB costs, was offset by a decrease in other deductions associated with non-service pension and OPEB costs ($14.0 million). With the elimination of pension and OPEB expenses in customer rates, Distribution Corporation’s New York service territory did not recognize any pension and OPEB expenses during 2023 compared to the prior year when it recognized pension and OPEB expenses to match against the pension and OPEB amounts collected in base rates.

Other factors that contributed to the earnings decrease in the Utility segment included higher operating expenses ($6.8 million) and higher interest expense ($8.6 million). The increase in operating expenses was mainly due to higher personnel costs and outside services. The increase in interest expense was largely the result of a higher weighted average interest rate on intercompany short-term borrowings combined with higher average short-term debt balances. There were also several factors that helped to reduce the earnings decrease year over year. The Utility segment's earnings benefited from the impact of the system modernization and system improvement trackers in New York ($3.8 million), lower income tax expense ($3.5 million) in New York and Pennsylvania, of which $1.7 million relates to a methodology change for the repair and maintenance tax deduction in Pennsylvania, higher capacity release revenues ($1.6 million), and a regulatory adjustment ($1.5 million). The Utility's Pennsylvania service territory also benefited from new rates that went into effect August 1, 2023 ($0.8 million).

The impact of weather variations on earnings in the Utility segment's New York rate jurisdiction is largely mitigated by that jurisdiction's weather normalization clause (WNC). The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. In addition, in periods of colder than normal weather, the WNC benefits the Utility segment's New York customers. For both 2023 and 2022, the WNC contributed approximately $4.8 million to earnings, as the weather was warmer than normal. Effective October 2023, the weather impact on cash flow in the Utility segment will also be mitigated by a WNC in its Pennsylvania rate jurisdiction.

ALL OTHER AND CORPORATE OPERATIONS

All Other and Corporate operations had a net loss of $4.0 million in 2023, an improvement of $8.7 million when compared with a net loss of $12.7 million in 2022. The improvement was primarily attributable to changes in unrealized gains and losses on investments in equity securities. In 2023, the Company recorded unrealized gains of $0.7 million, while in 2022, the Company recorded unrealized losses of $9.2 million. Other contributing factors include an increase in the cash surrender value of life insurance policies ($1.3 million), an increase in interest income on temporary cash investments ($1.3 million) and lower non-service pension and post-retirement benefit costs ($2.1 million). These changes were partially offset by a decrease in realized gains from sales of investments in equity securities ($2.9 million), as well as an increase in operating expenses as a result of an increase in professional services ($2.7 million).

OTHER INCOME (DEDUCTIONS)

Although most of the variances in Other Income (Deductions) are discussed in the earnings discussion by segment above, the following is a summary on a consolidated basis (amounts below are pre-tax amounts):

Net other income on the Consolidated Statements of Income was $18.1 million in 2023 compared to net other deductions of $1.5 million in 2022, for a net increase of $19.6 million. This was mostly due to changes in unrealized and realized gains and losses on investments in equity securities of $10.4 million, along with an increase in the cash surrender value of life insurance policies of $1.3 million. Higher interest income of $5.0 million also contributed to the increase, which resulted from an increase in interest on temporary cash investments, an increase in interest on a larger undercollection of gas costs over the prior year in Distribution Corporation and an increase in interest income earned on investments. The mark-to-market valuation adjustment for the contingent consideration received from the sale of Seneca's California assets in June 2022 was a loss of $0.9 million during 2023 as compared to a loss of $4.4 million during 2022. There was also a $1.9 million increase in non-service pension and post-retirement benefit income year over year. Offsetting these increases was a $2.3 million reduction in allowance for funds used during construction.

INTEREST CHARGES

Although most of the variances in Interest Charges are discussed in the earnings discussion by segment above, the following is a summary on a consolidated basis (amounts below are pre-tax amounts):

Interest on long-term debt decreased $8.6 million in 2023 as compared to 2022. The Company redeemed $150.0 million of the $500.0 million 3.75% notes in November 2022. In addition, $350.0 million of $500.0 million 3.75% notes and $49.0 million of 7.395% notes were redeemed in March 2023. These redemptions were partially offset by the issuance of $300.0 million of 5.50% notes in May 2023.

Other interest expense increased $10.1 million in 2023 as compared to 2022. The increase was primarily due to higher weighted average interest rates for 2023 partially offset by lower average short-term debt balances in 2023 compared to 2022.

CAPITAL RESOURCES AND LIQUIDITY

The primary sources and uses of cash during the last two years are summarized in the following condensed statement of cash flows:

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The Company expects to have adequate amounts of cash available to meet both its short-term and long-term cash requirements for at least the next twelve months and for the foreseeable future thereafter. During 2024, cash provided by operating activities is forecasted to be lower than 2023 largely due to a decrease in working capital sources, but is expected to be more than enough to fund the Company's capital expenditures. Looking forward to 2025, based on current commodity prices, cash provided by operating activities is again expected to exceed capital expenditures. The Company also has two long-term debt maturities in 2025, totaling $500.0 million, which the Company anticipates funding with cash on hand and short-term and long-term borrowings. These cash flow projections do not reflect the impact of acquisitions or divestitures that may arise in the future.

OPERATING CASH FLOW

Internally generated cash from operating activities consists of net income available for common stock, adjusted for non-cash expenses, non-cash income, gains and losses associated with investing and financing activities, and changes in operating assets and liabilities. Non-cash items include depreciation, depletion and amortization, impairment of oil and gas producing properties, deferred income taxes, the reduction of an other post-retirement regulatory liability and stock-based compensation.

Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from year to year because of the impact of rate cases. In the Utility segment, supplier refunds, over- or under-recovered purchased gas costs and weather may also significantly impact cash flow. The impact of weather on cash flow is tempered in the Pipeline and Storage segment by the straight fixed-variable rate design used by Supply Corporation and Empire. Prior to October 2023, the weather impact on cash flow in the Utility segment was mitigated by a WNC solely in its New York rate jurisdiction. However, effective October 2023, the weather impact on cash flow in the Utility segment will also be mitigated by a WNC in its Pennsylvania rate jurisdiction. Refer to Item 8 at Note A — Summary of Significant Accounting Policies (Regulatory Mechanisms) for additional discussion.

Cash provided by operating activities in the Exploration and Production segment may vary from year to year as a result of changes in the commodity prices of natural gas as well as changes in production. The Company uses various derivative financial instruments, including price swap agreements and no cost collars, in an attempt to manage this energy commodity price risk.

The Company, in its Utility segment and Exploration and Production segment, has entered into contractual commitments in the ordinary course of business, including commitments to purchase gas, transportation, and storage service to meet customer gas supply needs. Refer to Item 8 at Note L — Commitments and Contingencies under the heading “Other” for additional discussion concerning these contractual commitments as well as the amounts of future gas purchase, transportation and storage contract commitments expected to be incurred during the next five years and thereafter. Also refer to Item 8 at Note D — Leases for a discussion of the Company’s operating lease arrangements and a schedule of lease payments during the next five years and thereafter.

Net cash provided by operating activities totaled $1,237.1 million in 2023, an increase of $424.6 million compared with the $812.5 million provided by operating activities in 2022. The increase in cash provided by operating activities primarily reflects higher cash provided by operating activities in the Exploration and Production segment and Utility segment. The increase in the Exploration and Production segment is primarily due to higher cash receipts from natural gas production, net of royalty and working interests. The increase in the Utility segment is primarily due to the timing of gas cost recovery and the timing of customer receivable balance collections.

INVESTING CASH FLOW

Expenditures for Long-Lived Assets

The Company’s expenditures for long-lived assets, including non-cash capital expenditures, totaled $1.12 billion and $829.4 million in 2023 and 2022, respectively. The table below presents these expenditures:

(1) The year ended September 30, 2023 includes $124.8 million related to the acquisition of upstream assets acquired from SWN. The acquisition cost is reported as a component of Acquisition of Upstream Assets on the Consolidated Statement of Cash Flows.

(2) 2023 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $43.2 million, $31.8 million, $20.6 million and $13.6 million, respectively, of non-cash capital expenditures.

(3) 2022 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $83.0 million, $15.2 million, $10.7 million and $11.4 million, respectively, of non-cash capital expenditures.

Exploration and Production

In 2023, the Exploration and Production segment capital expenditures were primarily well drilling and completion expenditures in the Appalachian region and included $292.6 million in the Marcellus Shale area and $430.7 million in the Utica Shale area. These amounts included approximately $342.0 million spent to develop proved undeveloped reserves.

On June 1, 2023, the Company completed its acquisition of certain upstream assets located primarily in Tioga County, Pennsylvania from SWN for total consideration of $124.8 million. As part of the transaction, the Company acquired approximately 34,000 net acres in an area that is contiguous with existing Company-owned upstream assets. This transaction was accounted for as an asset acquisition and, as such, the purchase price was allocated to property, plant and equipment.

Other 2023 acquisitions included the acquisition of certain upstream assets located in Lycoming County in Northeast Pennsylvania for total consideration of $11.5 million as well as the acquisition of undeveloped acreage in Tioga County, Pennsylvania for $13.6 million. The acquisition in Lycoming County included 1,145 net acres and the acquisition in Tioga County included 4,222 net acres. Both transactions were accounted for as asset acquisitions and, as such, the purchase price for each transaction was allocated to property, plant and equipment. The cost of these acquisitions is reported as a component of Capital Expenditures on the Consolidated Statement of Cash Flows.

In 2022, the Exploration and Production segment capital expenditures were primarily well drilling and completion expenditures and included approximately $547.1 million for the Appalachian region (including $161.4 million in the Marcellus Shale area and $370.6 million in the Utica Shale area) and $18.7 million for the

West Coast region. These amounts included approximately $154.3 million spent to develop proved undeveloped reserves.

Pipeline and Storage

The Pipeline and Storage segment’s capital expenditures for 2023 were primarily for additions, improvements and replacements to this segment's transmission and gas storage systems, which included system modernization expenditures that enhance the reliability and safety of the systems and reduce emissions.

The Pipeline and Storage segment’s capital expenditures for 2022 were primarily for additions, improvements and replacements to this segment's transmission and gas storage systems, which included system modernization expenditures that enhance the reliability and safety of the systems and reduce emissions. In addition, the Pipeline and Storage segment capital expenditures for 2022 include expenditures related to Supply Corporation's FM100 Project ($25.2 million).

Gathering

The majority of the Gathering segment's capital expenditures for 2023 included expenditures related to the continued expansion of Midstream Company's Clermont, Tioga and Trout Run gathering systems, as discussed below. The Tioga gathering system refers to the gathering system owned by NFG Midstream Covington, LLC (Covington), which includes the gathering system previously owned by NFG Midstream Wellsboro, LLC (Wellsboro). Wellsboro was merged into Covington effective August 31, 2023. The merger of Wellsboro into Covington reflects the completion of a pipeline that connects the two systems. Midstream Company spent $20.7 million, $71.2 million and $10.8 million, respectively, in 2023 on the development of the Clermont, Tioga and Trout Run gathering systems. These expenditures were largely attributable to the installation of new in-field gathering pipelines related to bringing new development online, as well as the continued development of centralized station facilities, including increased dehydration capacity and compression horsepower.

The majority of the Gathering segment's capital expenditures for 2022 included expenditures related to the continued expansion of Midstream Company's Clermont, Covington, Trout Run and Wellsboro gathering systems. Midstream Company spent $20.9 million, $27.0 million, $4.9 million and $2.3 million in 2022 on the development of the Clermont, Covington, Trout Run and Wellsboro gathering systems, respectively. These expenditures were largely attributable to the installation of new in-field gathering pipelines in the Clermont gathering system, as well as the continued expansion of centralized station facilities, including increased compression horsepower at the Clermont, Trout Run, and Wellsboro gathering systems. In Covington, expenditures were largely attributable to the installation of in-field gathering pipelines and upgraded station facilities related to new development.

Utility

The majority of the Utility segment’s capital expenditures for 2023 and 2022 were made for main and service line improvements and replacements that enhance the reliability and safety of the system and reduce emissions. Expenditures were also made for main extensions.

Other Investing Activities

In October 2021, the Company sold $30 million of fixed income mutual fund shares held in a grantor trust that was established for the benefit of Pennsylvania ratepayers. The proceeds were used in the Utility segment’s Pennsylvania service territory to fund a one-time customer bill credit of $25 million in October 2021 for previously overcollected OPEB expenses and the first year installment of a 5-year pass back of an additional $29 million in previously overcollected OPEB expenses in accordance with new rates that went into effect on October 1, 2021. In October 2022, the Company sold an additional $10 million of fixed income mutual fund shares held in the grantor trust. The proceeds from this sale were used to fund the second year installment of the 5-year pass back of overcollected OPEB expenses, as well as to diversify a portion of grantor trust investments into lower risk money market mutual fund shares. Please refer to the Rate Matters section that follows for additional discussion of this matter.

In March 2022, the Company completed the sale of certain oil and gas assets located in Tioga County, Pennsylvania effective as of October 1, 2021. The Company received net proceeds of $13.5 million from this sale. Under the full cost method of accounting for oil and natural gas properties, the sale proceeds were accounted for as a reduction of capitalized costs. Since the disposition did not significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center, the Company did not record any gain or loss from this sale.

On June 30, 2022, the Company completed the sale of Seneca’s California assets, all of which were 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 fair value of the contingent consideration was $7.3 million at September 30, 2023. 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 a 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.

Estimated Capital Expenditures

The Company’s estimated capital expenditures for the next three years are:

(1) Includes estimated expenditures for the years ended September 30, 2024, 2025 and 2026 of approximately $315 million, $225 million and $120 million, respectively, to develop proved undeveloped reserves. The Company is committed to developing its proved undeveloped reserves within five years as required by the SEC’s final rule on Modernization of Oil and Gas Reporting.

(2) Includes estimated expenditures for the years ended September 30, 2024, 2025, and 2026 of approximately $115 million, $115 million and $120 million, respectively, for system modernization and safety to enhance the reliability and safety of the system and reduce emissions.

Exploration and Production

Capital expenditures for the Exploration and Production segment in 2024 through 2026 are expected to be primarily well drilling and completion expenditures in the Appalachian region.

Pipeline and Storage

Capital expenditures for the Pipeline and Storage segment in 2024 through 2026 are expected to include: the replacement and modernization of transmission and storage facilities, the reconditioning of storage wells, improvements of compressor stations and emissions reduction initiatives, as well as capital expenditures related to system expansion.

In addition, due to the continuing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia, specifically in the Marcellus and Utica Shale producing areas, Supply Corporation and Empire have completed and continue to pursue expansion projects designed to move anticipated Marcellus and Utica production gas to other interstate pipelines and to on-system markets, and markets beyond the Supply Corporation and Empire pipeline systems. An expansion and modernization project where the Company has forecasted a significant amount of investment in preliminary survey and investigation costs and/or capital expenditures in 2024 through 2026, and where a precedent agreement has been executed, is discussed below.

Supply Corporation concluded an Open Season on August 25, 2023, and based on post-open season discussions, has designed a project that would allow for the transportation of 190,000 Dth per day of shale gas supplies from a new interconnection in northwest Tioga County, Pennsylvania to an existing Supply Corporation interconnection with Tennessee Gas Pipeline Company, LLC at Ellisburg and a new virtual delivery point into an existing Transcontinental Gas Pipe Line Company, LLC’s (“Transco”) capacity lease, providing access to Mid-Atlantic markets (“Tioga Pathway Project”). The Tioga Pathway Project involves the construction of approximately 19 miles of new pipeline and the replacement of approximately four miles of existing pipeline on the Supply Corporation system. Supply Corporation has executed a Precedent Agreement with Seneca for 190,000 Dth per day of transportation capacity. Supply Corporation expects to file a Section 7(c) application with the FERC in the second half of calendar 2024. The Tioga Pathway project has a projected in-service date of late calendar year 2026 and an estimated capital cost of approximately $90 million. The majority of these expenditures are included as Pipeline and Storage segment estimated capital expenditures in the table above. As of September 30, 2023, less than $0.1 million has been spent to study this project, all of which has been included in Deferred Charges on the Consolidated Balance Sheet at September 30, 2023.

Gathering

The majority of the Gathering segment capital expenditures in 2024 through 2026, included in the table above, are expected to be for construction and expansion of gathering systems, as discussed below. The Gathering segment primarily invests capital to support Seneca's drilling and completion activity in their long-term development plan. Seneca has shifted a larger share of its forward-looking activity from its Western Development Area to Tioga County, Pennsylvania. As a result, the Gathering segment is expecting to see near-term increases in capital expenditures as it constructs the necessary infrastructure to support Seneca's activity in the region.

Utility

Capital expenditures for the Utility segment in 2024 through 2026 are expected to be concentrated in the areas of main and service line improvements and replacements that will enhance the reliability and safety of the system, emission reduction initiatives and, to a lesser extent, the purchase of new equipment.

Project Funding

During fiscal 2023 and 2022, capital expenditures were funded with cash from operations and short-term debt. Capital expenditures in fiscal 2022 were also funded with proceeds from the sale of the Company's California assets. Going forward, the Company expects to use cash on hand, cash from operations and short-term or long-term borrowings, as needed, to finance capital expenditures. The level of short-term and/or long-term borrowings will depend upon the amount of cash provided by operations, which, in turn, will likely be most impacted by natural gas production and the associated commodity price realizations in the Exploration and Production segment. It will also likely depend on the timing of gas cost recovery in the Utility segment.

In the Exploration and Production segment, the Company has entered into contractual obligations to support its development activities and operations in Pennsylvania, including hydraulic fracturing and other well completion services, well tending services, well workover activities, tubing and casing purchases, production equipment purchases, water hauling services and contracts for drilling rig services. Refer to Item 8 at Note L — Commitments and Contingencies under the heading “Other” for the amounts of contractual obligations expected to be incurred during the next five years and thereafter to support the Company’s exploration and development activities. These amounts are largely a subset of the estimated capital expenditures for the Exploration and Production segment shown above.

The Company, in its Pipeline and Storage segment, Gathering segment and Utility segment, has entered into several contractual commitments associated with various pipeline, compressor and gathering system modernization and expansion projects. Refer to Item 8 at Note L — Commitments and Contingencies under the heading “Other” for the amounts of contractual commitments expected to be incurred during the next five years and thereafter associated with the Company’s pipeline, compressor and gathering system modernization and expansion projects. These amounts are a subset of the estimated capital expenditures for the Pipeline and Storage segment, Gathering segment and Utility segment that are shown above.

The Company continuously evaluates capital expenditures and potential investments in corporations, partnerships, and other business entities. The amounts are subject to modification for opportunities such as the acquisition of attractive natural gas properties, accelerated development of existing natural gas properties, natural gas storage and transmission facilities, natural gas gathering and compression facilities and the expansion of natural gas transmission line capacities, regulated utility assets and other opportunities as they may arise. The amounts are also subject to modification for opportunities involving emission reductions and/or energy transition including investments directly related to low- and no-carbon fuels. While the majority of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company’s business segments depends, to a large degree, upon market and regulatory conditions as well as legislative actions.

FINANCING CASH FLOW

Consolidated short-term debt increased $227.5 million, to a total of $287.5 million, when comparing the balance sheet at September 30, 2023 to the balance sheet at September 30, 2022. The maximum amount of short-term debt outstanding during the year ended September 30, 2023 was $422.3 million. In addition to cash provided by operating activities, the Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures, asset purchases, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, other working capital needs and repayment of long-term debt. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. During fiscal 2023, the Company repaid $549.0 million of long-term debt with maturity dates in March 2023 and issued $300.0 million of additional long-term debt in May 2023. The net reduction in long-term debt resulted in an increase in the short-term debt balance. As of September 30, 2023, the Company had outstanding commercial paper of $287.5 million. The Company did not have any short-term notes payable to banks as of September 30, 2023.

On February 28, 2022, the Company entered into a Credit Agreement (as amended from time to time, the "Credit Agreement") with a syndicate of twelve banks. The Credit Agreement replaced the previous Fourth Amended and Restated Credit Agreement and a previous 364-Day Credit Agreement. The Credit Agreement provides a $1.0 billion unsecured committed revolving credit facility with a maturity date of February 26, 2027.

On June 30, 2022, the Company entered into a 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 provided 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 25, 2022 redemption of a portion of the Company's outstanding long-term debt with a maturity date of March 1, 2023. All indebtedness under the 364-Day Credit Agreement was repaid on May 18, 2023.

The Company also has uncommitted lines of credit with financial institutions for general corporate purposes. Borrowings under these uncommitted lines of credit would be made at competitive market rates. The uncommitted credit lines are revocable at the option of the financial institution and are reviewed on an annual basis. The Company anticipates that its uncommitted lines of credit generally will be renewed or substantially replaced by similar lines. Other financial institutions may also provide the Company with uncommitted or discretionary lines of credit in the future.

The total amount available to be issued under the Company’s commercial paper program is $500.0 million. The commercial paper program is backed by the Credit Agreement, which provides that the Company's debt to capitalization ratio will not exceed 0.65 at the last day of any fiscal quarter. For purposes of calculating the debt to capitalization ratio, the Company's total capitalization will be increased by adding back 50% of the aggregate after-tax amount of non-cash charges directly arising from any ceiling test impairment occurring on or after July 1, 2018, not to exceed $400 million. Since July 1, 2018, the Company recorded non-cash, after-tax ceiling test impairments totaling $381.4 million. As a result, at September 30, 2023, $190.7 million was added back to the Company's total capitalization for purposes of the calculation under the Credit Agreement. On May 3, 2022, the Company entered into Amendment No. 1 to the Credit Agreement with the same twelve banks under the initial Credit Agreement. The amendment further modified the definition of consolidated capitalization, for purposes of calculating the debt to capitalization ratio under the Credit Agreement, to exclude, beginning with the quarter ended June 30, 2022, all unrealized gains or losses on commodity-related derivative financial instruments and up to $10 million in unrealized gains or losses on other derivative financial instruments included in Accumulated Other Comprehensive Income (Loss) within Total Comprehensive Shareholders' Equity on the Company's consolidated balance sheet. Under the Credit Agreement, such unrealized losses will not negatively affect the calculation of the debt to capitalization ratio, and such unrealized gains will not positively affect the calculation. At September 30, 2023, the Company’s debt to capitalization ratio, as calculated under the Credit Agreement was 0.46. The constraints specified in the Credit Agreement would have permitted an additional $3.17 billion in short-term and/or long-term debt to be outstanding at September 30, 2023 before the Company’s debt to capitalization ratio exceeded 0.65.

A downgrade in the Company’s credit ratings could increase borrowing costs, negatively impact the availability of capital from banks, commercial paper purchasers and other sources, and require the Company's subsidiaries to post letters of credit, cash or other assets as collateral with certain counterparties. If the Company is not able to maintain investment-grade credit ratings, it may not be able to access commercial paper markets. However, the Company expects that it could borrow under its credit facilities or rely upon other liquidity sources.

The Credit Agreement contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $40.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity.

On May 18, 2023, the Company issued $300.0 million of 5.50% notes due October 1, 2026. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $297.3 million. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade. Additionally, the interest rate payable on the notes will be subject to adjustment from time to time, with a maximum adjustment of 2.00%, such that the coupon will not exceed 7.50%, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to a rating below investment grade. A downgrade with a resulting increase to the coupon does not preclude the coupon from returning to its original rate if the Company's credit rating is subsequently upgraded. The proceeds of this debt issuance were used for general corporate purposes, including to repay all indebtedness under the $250.0 million unsecured committed delayed draw term loan under the 364-Day Credit Agreement.

None of the Company's long-term debt as of September 30, 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, that each had maturity dates in March 2023. The Company utilized short-term borrowings and cash on hand to repay $150.0 million of these maturities in November 2022 and the remaining $399.0 million in March 2023. As of September 30, 2023, the future contractual obligations related to aggregate principal amounts of long-term debt, including interest expense, maturing during the next five years and thereafter are as follows: $111.9 million in 2024, $605.9 million in 2025, $565.4 million in 2026, $640.4 million in 2027, $327.9 million in 2028, and $535.7 million thereafter. Refer to Item 8 at Note H — Capitalization and Short-Term Borrowings, as well as the table under Interest Rate Risk in the Market Risk Sensitive Instruments section below, for the amounts excluding interest expense. Principal payments of long-term debt are a component of cash used in financing activities while interest payments on long-term debt are a component of cash used in operating activities.

The Company’s embedded cost of long-term debt was 4.69% at September 30, 2023 and 4.48% at September 30, 2022. Refer to “Interest Rate Risk” in this Item for a more detailed breakdown of the Company’s embedded cost of long-term debt.

Under the Company's existing indenture covenants at September 30, 2023, the Company would have been permitted to issue up to a maximum of approximately $3.43 billion in additional unsubordinated long-term indebtedness at then current market interest rates, in addition to being able to issue new indebtedness to replace existing debt (further limited by the debt to capitalization ratio constraint under the Company's Credit Agreement, as discussed above). The Company's present liquidity position is believed to be adequate to satisfy known demands. It is possible, depending on amounts reported in various income statement and balance sheet line items, that the indenture covenants could, for a period of time, prevent the Company from issuing incremental unsubordinated long-term debt, or significantly limit the amount of such debt that could be issued. Losses incurred as a result of significant impairments of oil and gas properties have in the past resulted in such temporary restrictions. The indenture covenants would not preclude the Company from issuing new long-term debt to replace existing long-term debt, or from issuing additional short-term debt. Please refer to the Critical Accounting Estimates section above for a sensitivity analysis concerning commodity price changes and their impact on the ceiling test.

The Company’s 1974 indenture pursuant to which $50.0 million (or 2.1%) of the Company’s long-term debt (as of September 30, 2023) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement, or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.

OTHER MATTERS

In addition to the environmental and other matters discussed in this Item 7 and in Item 8 at Note L — Commitments and Contingencies, the Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations or other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.

Supply Corporation and Empire have developed a project which would move significant prospective Marcellus and Utica production from Seneca's Western Development Area at Clermont to an Empire interconnection with the TC Energy pipeline at Chippawa and an interconnection with TGP's 200 Line in East Aurora, New York (the “Northern Access project”). The Northern Access project would provide an outlet to Dawn-indexed markets in Canada and to the TGP line serving the U.S. Northeast. The Northern Access project involves the construction of approximately 99 miles of largely 24” pipeline and approximately 27,500 horsepower of compression on the two systems. Supply Corporation, Empire and Seneca executed anchor shipper agreements for 350,000 Dth per day of firm transportation delivery capacity to Chippawa and 140,000 Dth per day of firm transportation capacity to a new interconnection with TGP's 200 Line on this project. 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, which is the subject of an ongoing appeal at the U.S. Court of Appeals for the D.C. Circuit. The Company will update the $500 million preliminary cost estimate and expected in-service date for the project when there is further clarity on the timing of receipt of necessary regulatory approvals, including the completion of ongoing litigation. As of September 30, 2023, approximately $55.9 million has been spent on the Northern Access project, including $24.3 million that has been spent to study the project that is included in Deferred Charges on the Consolidated Balance Sheet. The remaining $31.6 million spent on the project is included in Property, Plant and Equipment on the Consolidated Balance Sheet at September 30, 2023.

The Company has a tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan). During 2023, the Company did not make any contributions to the Retirement Plan. Estimated contributions to the Retirement Plan in 2024 will be in the range of zero to $5.0 million. For further discussion of the Company’s Retirement Plan, including actuarial assumptions, refer to Item 8 at Note K — Retirement Plan and Other Post-Retirement Benefits. As noted in that footnote, the Retirement Plan has been closed to new participants since 2003. In that regard, the average remaining service life of active participants in the Retirement Plan is approximately 6 years.

The Company provides health care and life insurance benefits (other post-retirement benefits) for a majority of its retired employees. The Company has established VEBA trusts and 401(h) accounts for its other post-retirement benefits. The Company has been making contributions to its VEBA trusts and/or 401(h) accounts over the last several years and does not anticipate making contributions to the VEBA trusts and/or 401(h) accounts in the near term. However, this will be subject to future review. During 2023, the Company did not make any contributions to its VEBA trusts. However, the Company made direct payments of $0.2 million to retirees not covered by the VEBA trusts and 401(h) accounts during 2023. The Company does not expect to make any contributions to its VEBA trusts in 2024. For further discussion of the Company’s other post-retirement benefits, including actuarial assumptions, refer to Item 8 at Note K — Retirement Plan and Other Post-Retirement Benefits. As noted in that footnote, the other post-retirement benefits provided by the Company have been closed to new participants since 2003. In that regard, the average remaining service life of active participants is approximately 4 years for those eligible for other post-retirement benefits.

The Company has made certain guarantees on behalf of its subsidiaries. The guarantees relate primarily to: (i) obligations under derivative financial instruments, which are included on the Consolidated Balance Sheets in accordance with the authoritative guidance (see Item 7, MD&A under the heading “Critical Accounting Estimates - Accounting for Derivative Financial Instruments”); and (ii) other obligations which are reflected on the Consolidated Balance Sheets. The Company believes that the likelihood it would be required to make payments under the guarantees is remote.

MARKET RISK SENSITIVE INSTRUMENTS

Energy Commodity Price Risk

The Company uses various derivative financial instruments (derivatives), including price swap agreements and no cost collars, as part of the Company’s overall energy commodity price risk management strategy in its Exploration and Production segment. Under this strategy, the Company manages a portion of the market risk associated with fluctuations in the price of natural gas, thereby attempting to provide more stability to operating results. The Company has operating procedures in place that are administered by experienced management to monitor compliance with the Company’s risk management policies. The derivatives are not held for trading purposes. The fair value of these derivatives, as shown below, represents the amount that the Company would receive from, or pay to, the respective counterparties at September 30, 2023 to terminate the derivatives. However, the tables below and the fair value that is disclosed do not consider the physical side of the natural gas transactions that are related to the financial instruments.

On July 21, 2010, the Dodd-Frank Act was signed into law. The Dodd-Frank Act required the CFTC, SEC and other regulatory agencies to promulgate rules and regulations implementing the legislation, and includes provisions related to the swaps and over-the-counter derivatives markets that are designed to promote transparency, mitigate systemic risk and protect against market abuse. Although regulators have adopted several final regulations, other rules that may impact the Company have yet to be finalized. Rules adopted by the CFTC and other regulators could adversely impact the Company. While many of those rules place specific conditions on the operations of swap dealers rather than directly on the Company, concern remains that swap dealers with whom the Company may transact will pass along their increased costs stemming from final rules through higher transaction costs and prices or other direct or indirect costs. Some of those rules also may apply directly to the Company and adversely impact its ability to trade swaps and over-the-counter derivatives, whether due to increased costs, limitations on trading capacity or for other reasons. Additionally, given the enforcement authority granted to the CFTC on anti-market manipulation, anti-fraud and anti-disruptive trading practices, it is difficult to predict how the evolving enforcement priorities of the CFTC will impact our business. Should the Company violate any laws or regulations applicable to our hedging activities, it could be subject to CFTC enforcement action and material penalties and sanctions. The Company cannot predict the impact that evolving application of the Dodd-Frank Act may have on its operations.

The authoritative guidance for fair value measurements and disclosures requires consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At September 30, 2023, the Company determined that nonperformance risk associated with its natural gas price swap agreements, natural gas no cost collars and foreign currency contracts would have no material impact on its financial position or results of operation. To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates.

The following tables disclose natural gas price swap information by expected maturity dates for agreements in which the Company receives a fixed price in exchange for paying a variable price as quoted in various national natural gas publications or on the NYMEX. Notional amounts (quantities) are used to calculate the contractual payments to be exchanged under the contract. The weighted average variable prices represent the weighted average settlement prices by expected maturity date as of September 30, 2023. At September 30, 2023, the Company had not entered into any natural gas price swap agreements extending beyond 2028.

Natural Gas Price Swap Agreements

At September 30, 2023, the Company would have paid its respective counterparties an aggregate of approximately $2.5 million to terminate the natural gas price swap agreements outstanding at that date.

At September 30, 2022, the Company had natural gas price swap agreements covering 207.3 Bcf at a weighted average fixed rate of $2.98 per Mcf.

No Cost Collars

The following table discloses the notional quantities, the weighted average ceiling price and the weighted average floor price for the no cost collars used by the Company to manage natural gas price risk. The no cost collars provide for the Company to receive monthly payments from (or make payments to) other parties when a variable price falls below an established floor price (the Company receives payment from the counterparty) or exceeds an established ceiling price (the Company pays the counterparty). At September 30, 2023, the Company had not entered into any natural gas no cost collars extending beyond 2027.

At September 30, 2023, the Company would have received an aggregate of approximately $16.0 million to terminate the natural gas no cost collars outstanding at that date.

At September 30, 2022, the Company had no cost collars agreements covering 213.5 Bcf at a weighted average ceiling price of $4.24 per Mcf and a weighted average floor price of $3.40 per Mcf.

Foreign Exchange Risk

The Company uses 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. All of these transactions are forecasted.

The following table discloses foreign exchange contract information by expected maturity dates. The Company receives a fixed price in exchange for paying a variable price as noted in the Canadian to U.S. dollar forward exchange rates. Notional amounts (Canadian dollars) are used to calculate the contractual payments to be exchanged under contract. The weighted average variable prices represent the weighted average settlement prices by expected maturity date as of September 30, 2023. At September 30, 2023, the Company had not entered into any foreign currency exchange contracts extending beyond 2030.

At September 30, 2023, absent other positions with the same counterparties, the Company would have paid to its respective counterparties an aggregate of $1.3 million to terminate these foreign exchange contracts.

Refer to Item 8 at Note J — Financial Instruments for a discussion of the Company’s exposure to credit risk related to its derivative financial instruments.

Interest Rate Risk

The fair value of long-term fixed rate debt is $2.2 billion at September 30, 2023. This fair value amount is not intended to reflect principal amounts that the Company will ultimately be required to pay. The following table presents the principal cash repayments and related weighted average interest rates by expected maturity date for the Company’s long-term fixed rate debt:

(Dollars in millions)

RATE MATTERS

Utility Operation

Delivery rates for both the New York and Pennsylvania divisions are regulated by the states’ respective public utility commissions and typically are changed only when approved through a procedure known as a “rate case.” As noted below, the New York division currently has a rate case on file. In both jurisdictions, delivery rates do not reflect the recovery of purchased gas costs. Prudently-incurred gas costs are recovered through operation of automatic adjustment clauses, and are collected primarily through a separately-stated “supply charge” on the customer bill.

New York Jurisdiction

Distribution Corporation's current delivery rates in its New York jurisdiction were approved by the NYPSC in an order issued on April 20, 2017 with rates becoming effective May 1, 2017 ("2017 Rate Order"). The 2017 Rate 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. On October 31, 2023, Distribution Corporation made a filing with the NYPSC seeking an increase of $88.8 million in its total annual operating revenues for the projected rate year ending September 30, 2025, with a proposed effective date of October 1, 2024 that includes the maximum suspension period permitted under the New York Public Service Law ("2023 Rate Filing"). The Company is also proposing, among other things, to continue its leak prone pipe replacement program and to implement a number of initiatives that will facilitate achievement of the emissions reduction goals of the Climate Leadership and Community Protection Act.

The 2017 Rate Order 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 temporary 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. With the implementation of this surcredit, Distribution Corporation ceased funding the Retirement Plan and its VEBA trusts in its New York jurisdiction. The 2023 Rate Filing proposes to keep the rate recovery of pension and OPEB costs at zero in the rate year and reflect the $15 million of savings in new base delivery rates.

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 by 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. The 2023 Rate Filing proposes to stop accruing and collecting revenues under its current system modernization and system improvement trackers and shift those revenues into the Company’s new base delivery rates. In the absence of a multi-year rate plan settlement, the Company is requesting that it be allowed to reinstate a tracking mechanism similar to the existing system modernization tracker.

Pennsylvania Jurisdiction

Distribution Corporation’s delivery rates effective through July 31, 2023 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. A settlement involving all active parties to the proceeding was reached and filed with the PaPUC on April 13, 2023. The settlement provided for, among other things, an increase in Distribution Corporation’s annual base rate operating revenues of $23 million. The PaPUC approved the settlement in full, without modification or correction, on June 15, 2023 and new rates went into effect on August 1, 2023.

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.

Pipeline and Storage

Supply Corporation filed a NGA Section 4 rate case at FERC on July 31, 2023 proposing rate increases to be effective February 1, 2024. The proposed rates reflect an annual cost of service of $385.4 million, a rate base of $1.32 billion and a proposed cost of equity of 15.12%. If the proposed rate increases finally approved at the end of the proceeding exceed the rates that were in effect at July 31, 2023, but are less than rates put into effect subject to refund on February 1, 2024, Supply Corporation would be required to refund the difference between the rates collected subject to refund and the final approved rates, with interest at the FERC-approved rate. If the rates approved at the end of the proceeding are lower than the rates in effect at July 31, 2023, such lower rates will become effective prospectively from the effective date provided by the applicable FERC order, and refunds with interest will be limited to the difference between the rates collected subject to refund and the rates in effect at July 31, 2023.

Empire’s 2019 rate settlement provides that Empire must make a rate case filing no later than May 1, 2025.

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 comply with regulatory requirements. In 2021, the Company set methane intensity reduction targets at each of its businesses, an absolute greenhouse gas emissions reduction target for the consolidated Company, and greenhouse gas reduction targets associated with the Company’s utility delivery system. In 2022, the Company began measuring progress against these reduction targets. The Company's ability to estimate accurately the time, costs and resources necessary to meet emissions targets may be impacted as environmental exposures, technology and opportunities change and regulatory and policy updates are issued.

For further discussion of the Company's environmental exposures, refer to Item 8 at Note L — Commitments and Contingencies under the heading “Environmental Matters.”

The effect (material or not) on the Company of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.

Environmental Regulation

Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation in the United States. These efforts include legislation, legislative proposals and new regulations at the state and federal level, and private party litigation related to greenhouse gas emissions. Legislation or regulation that aims to reduce greenhouse gas emissions could also include emissions limits, reporting requirements, carbon taxes, restrictive permitting, increased efficiency standards, and incentives or mandates to conserve energy or use renewable energy sources. For example, the federal Inflation Reduction Act of 2022 (IRA) legislation was signed into law on August 16, 2022. The IRA includes a methane charge that is expected to be applicable to the reported annual methane emissions of certain oil and gas facilities, above specified methane intensity thresholds, starting in calendar year 2024. This portion of the IRA is to be administered by the EPA and potential fees will begin with emissions reported for calendar year 2024. The EPA is the lead federal agency that regulates greenhouse gas emissions pursuant to the Clean Air Act. The regulations implemented by the EPA impose stringent leak detection and repair requirements and address reporting and control of methane and volatile organic compound emissions. The Company must continue to comply with all applicable regulations. Additionally, a number of states have adopted energy strategies or plans with aggressive goals for the reduction of greenhouse gas emissions. Pennsylvania has a methane reduction framework with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines. Federal, state or local governments may provide tax advantages and other subsidies to support alternative energy sources, mandate the use of specific fuels or technologies, or promote research into new technologies to reduce the cost and increase the scalability of alternative energy sources. The NYPSC, for example, initiated a proceeding to consider climate-related financial disclosures at the utility operating company level, and the New York State legislature passed the CLCPA that mandates reducing greenhouse gas emissions by 40% from 1990 levels by 2030, and by 85% from 1990 levels by 2050, with the remaining emission reduction achieved by controlled offsets. The CLCPA also requires electric generators to meet 70% of demand with renewable energy by 2030 and 100% with zero emissions generation by 2040. In May 2023, New York State passed legislation that prohibits the installation of fossil fuel burning equipment and building systems in new buildings commencing on or after December 31, 2025, subject to certain exemptions. These climate change and greenhouse gas initiatives could impact the Company's customer base and assets depending on the promulgation of final regulations and on regulatory treatment afforded in the process. The NYDEC has until January 1, 2024 to issue further rules and regulations implementing the CLCPA. The NYDEC, in conjunction with the New York State Energy Research and Development Authority, is also in the early phases of developing a cap-and-invest program in the state, which is anticipated to be effective in 2025. The above-enumerated initiatives could also increase the Company’s cost of environmental compliance by increasing reporting requirements, requiring retrofitting of existing equipment, requiring installation of new equipment, and/or requiring the purchase of emission allowances. They could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals. Changing market conditions and new regulatory requirements, as well as unanticipated or inconsistent application of existing laws and regulations by administrative agencies, make it difficult to predict a long-term business impact across twenty or more years.

EFFECTS OF INFLATION

The Company’s operations are sensitive to increases in the rate of inflation because of its operational and capital spending requirements in both its regulated and non-regulated businesses. For the regulated businesses, recovery of increasing costs from customers can be delayed by the regulatory process of a rate case filing. For the non-regulated businesses, prices received for services performed or products produced are determined by market factors that are not necessarily correlated to the underlying costs required to provide the service or product.

SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

The Company is including the following cautionary statement in this Annual Report on Form 10-K to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Certain statements contained in this report, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new authoritative accounting and reporting guidance, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements:

1. Changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing;

2. Governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, target rates of return, rate design, retained natural gas and system modernization), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal;

3. The Company’s ability to estimate accurately the time and resources necessary to meet emissions targets;

4. Governmental/regulatory actions and/or market pressures to reduce or eliminate reliance on natural gas;

5. Changes in economic conditions, including inflationary pressures, supply chain issues, liquidity challenges, and global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services;

6. Changes in the price of natural gas;

7. The creditworthiness or performance of the Company’s key suppliers, customers and counterparties;

8. Financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions;

9. Impairments under the SEC’s full cost ceiling test for natural gas reserves;

10. Increased costs or delays or changes in plans with respect to Company projects or related projects of other companies, as well as difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators;

11. Changes in price differentials between similar quantities of natural gas sold at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations;

12. The impact of information technology disruptions, cybersecurity or data security breaches;

13. Factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas reserves, including among others geology, lease availability and costs, title disputes, weather conditions, water availability and disposal or recycling opportunities of used water, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations;

14. The Company's ability to complete strategic transactions;

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

16. Other changes in price differentials between similar quantities of natural gas having different quality, heating value, hydrocarbon mix or delivery date;

17. The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company;

18. Negotiations with the collective bargaining units representing the Company's workforce, including potential work stoppages during negotiations;

19. Uncertainty of natural gas reserve estimates;

20. Significant differences between the Company’s projected and actual production levels for natural gas;

21. Changes in demographic patterns and weather conditions (including those related to climate change);

22. Changes in the availability, price or accounting treatment of derivative financial instruments;

23. Changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities;

24. Economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities or acts of war, as well as economic and operational disruptions due to third-party outages;

25. Significant differences between the Company’s projected and actual capital expenditures and operating expenses; or

26. Increasing costs of insurance, changes in coverage and the ability to obtain insurance.

The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.

Forward-looking and other statements in this Annual Report on Form 10-K regarding methane and greenhouse gas reduction plans and goals are not an indication that these statements are necessarily material to investors or required to be disclosed in our filings with the SEC. In addition, historical, current and forward-looking statements regarding methane and greenhouse gas emissions may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve and assumptions that are subject to change in the future.

INDUSTRY AND MARKET DATA DISCLOSURE

The market data and certain other statistical information used throughout this Form 10-K are based on independent industry publications, government publications or other published independent sources. Some data is also based on the Company's good faith estimates. Although the Company believes these third-party sources are reliable and that the information is accurate and complete, it has not independently verified the information.

Evaluation of Disclosure Controls and Procedures

The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, including the Chief Executive Officer and Principal Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the Company’s Chief Executive Officer and Principal Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2023.

Management’s Annual Report on Internal Control over Financial Reporting

The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with GAAP. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.

The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of September 30, 2023. In making this assessment, management used the framework and criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework, published in 2013. Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of September 30, 2023.

PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited the Company’s consolidated financial statements included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of the Company’s internal control over financial reporting as of September 30, 2023. The report appears in Part II, Item 8 of this Annual Report on Form 10-K.

Changes in Internal Control over Financial Reporting

There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended September 30, 2023 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.