UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||||||
For the Fiscal Year Ended September 30 , 2024
| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||||||
For the Transition Period from to
Commission File Number 1-3880
(Exact name of registrant as specified in its charter)
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |||||||
| (Address of principal executive offices) | (Zip Code) | |||||||
(716 ) 857-7000
(Registrant’s telephone number, including area code)
| Securities registered pursuant to Section 12(b) of the Act: | ||||||||
| Title of Each Class | Trading Symbol | Name of Each Exchange on Which Registered | ||||||
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☑ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act. Yes ☐ No ☑
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| ☑ | Accelerated filer | ☐ | |||||||||
| Non-accelerated filer | ☐ | Smaller reporting company | |||||||||
| Emerging growth company | |||||||||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☑
The aggregate market value of the voting stock held by nonaffiliates of the registrant amounted to $4,834,365,000 as of March 31, 2024.
Common Stock, par value $1.00 per share, outstanding as of October 31, 2024: 90,822,810 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Glossary of Terms
Frequently used abbreviations, acronyms, or terms used in this report:
National Fuel Gas Companies
Company The Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries as appropriate in the context of the disclosure
Distribution Corporation National Fuel Gas Distribution Corporation
Empire Empire Pipeline, Inc.
Midstream Company National Fuel Gas Midstream Company, LLC
National Fuel National Fuel Gas Company
Registrant National Fuel Gas Company
Seneca Seneca Resources Company, LLC
Supply Corporation National Fuel Gas Supply Corporation
Regulatory Agencies
CFTC Commodity Futures Trading Commission
EPA United States Environmental Protection Agency
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
IRS Internal Revenue Service
NYDEC New York State Department of Environmental Conservation
NYPSC State of New York Public Service Commission
PaPUC Pennsylvania Public Utility Commission
PHMSA Pipeline and Hazardous Materials Safety Administration
SEC Securities and Exchange Commission
Other
2017 Tax Reform Act Tax legislation referred to as the “Tax Cuts and Jobs Act,” enacted December 22, 2017.
Bbl Barrel (of oil)
Bcf Billion cubic feet (of natural gas)
Bcfe (or Mcfe) — represents Bcf (or Mcf) Equivalent The total heat value (Btu) of natural gas and oil expressed as a volume of natural gas. The Company uses a conversion formula of 1 barrel of oil = 6 Mcf of natural gas.
Btu British thermal unit; the amount of heat needed to raise the temperature of one pound of water one degree Fahrenheit.
Capital expenditure Represents additions to property, plant, and equipment, or the amount of money a company spends to buy capital assets or upgrade its existing capital assets.
Cashout revenues A cash resolution of a gas imbalance whereby a customer pays Supply Corporation and/or Empire for gas the customer receives in excess of amounts delivered into Supply Corporation’s and Empire’s systems by the customer’s shipper.
CLCPA Legislation referred to as the “Climate Leadership & Community Protection Act,” enacted by the State of New York on July 18, 2019.
Degree day A measure of the coldness of the weather experienced, based on the extent to which the daily average temperature falls below a reference temperature, usually 65 degrees Fahrenheit.
Derivative A financial instrument or other contract, the terms of which include an underlying variable (a price, interest rate, index rate, exchange rate, or other variable) and a notional amount (number of units, barrels, cubic feet, etc.). The terms also permit for the instrument or contract to be settled net and no initial net investment is required to enter into the financial instrument or contract. Examples include futures contracts, options, no cost collars and swaps.
Development costs Costs incurred to obtain access to proved gas and oil reserves and to provide facilities for extracting, treating, gathering and storing the gas and oil.
Development well A well drilled to a known producing formation in a previously discovered field.
Dodd-Frank Act Dodd-Frank Wall Street Reform and Consumer Protection Act.
Dth Decatherm; one Dth of natural gas has a heating value of 1,000,000 British thermal units, approximately equal to the heating value of 1 Mcf of natural gas.
ESG Environmental, social and governance
Exchange Act Securities Exchange Act of 1934, as amended
Expenditures for long-lived assets Includes capital expenditures, stock acquisitions and/or investments in partnerships.
Exploitation Development of a field, including the location, drilling, completion and equipment of wells necessary to produce the commercially recoverable oil and gas in the field.
Exploration costs Costs incurred in identifying areas that may warrant examination, as well as costs incurred in examining specific areas, including drilling exploratory wells.
Exploratory well A well drilled in unproven or semi-proven territory for the purpose of ascertaining the presence underground of a commercial hydrocarbon deposit.
Firm transportation and/or storage The transportation and/or storage service that a supplier of such service is obligated by contract to provide and for which the customer is obligated to pay whether or not the service is utilized.
GAAP Accounting principles generally accepted in the United States of America
Goodwill An intangible asset representing the difference between the fair value of a company and the price at which a company is purchased.
Hedging A method of minimizing the impact of price, interest rate, and/or foreign currency exchange rate changes, often through the use of derivative financial instruments.
Hub Location where pipelines intersect enabling the trading, transportation, storage, exchange, lending and borrowing of natural gas.
ICE Intercontinental Exchange. An exchange which maintains a futures market for crude oil and natural gas.
Impact Fee An annual fee imposed on unconventional wells spud in Pennsylvania. The fee is administered by the PaPUC and fees are distributed to counties and municipalities where the well is located.
Interruptible transportation and/or storage The transportation and/or storage service that, in accordance with contractual arrangements, can be interrupted by the supplier of such service, and for which the customer does not pay unless utilized.
LDC Local distribution company
LIFO Last-in, first-out
Marcellus Shale A Middle Devonian-age geological shale formation that is present nearly a mile or more below the surface in the Appalachian region of the United States, including much of Pennsylvania and southern New York.
Mbbl Thousand barrels (of oil)
Mcf Thousand cubic feet (of natural gas)
MD&A Management’s Discussion and Analysis of Financial Condition and Results of Operations
MDth Thousand decatherms (of natural gas)
Methane The primary component of natural gas. It is a compound made up of one carbon atom and four hydrogen atoms (CH4).
MMBtu Million British thermal units (heating value of one decatherm of natural gas)
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MMcf Million cubic feet (of natural gas)
MMcfe Million cubic feet equivalent
Natural Gas A naturally occurring mixture of gaseous hydrocarbons consisting primarily of methane and found in underground rock formations.
NGA The Natural Gas Act of 1938, as amended; the federal law regulating interstate natural gas pipeline and storage companies, among other things, codified beginning at 15 U.S.C. Section 717.
NOAA National Oceanic and Atmospheric Administration
NYMEX New York Mercantile Exchange. An exchange which maintains a futures market for crude oil and natural gas.
OPEB Other Post-Employment Benefit
Open Season A bidding procedure used by pipelines to allocate firm transportation or storage capacity among prospective shippers, in which all bids submitted during a defined time period are evaluated as if they had been submitted simultaneously.
PCB Polychlorinated Biphenyl
Precedent Agreement An agreement between a pipeline company and a potential customer to sign a service agreement after specified events (called “conditions precedent”) happen, usually within a specified time.
Proved developed reserves Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved undeveloped (PUD) reserves Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required to make those reserves productive.
Reliable technology Technology that a company may use to establish reserves estimates and categories that has been proven empirically to lead to correct conclusions.
Reserves The unproduced but recoverable oil and/or gas in place in a formation which has been proven by production.
Revenue decoupling mechanism A rate mechanism which adjusts customer rates to render a utility financially indifferent to throughput decreases resulting from conservation.
S&P Standard & Poor’s Ratings Service
SAR Stock appreciation right
Section 7(c) application An application to the FERC under Section 7(c) of the federal Natural Gas Act for authority to construct, operate (and provide services through) facilities to transport or store natural gas in interstate commerce.
Service Agreement The binding agreement by which the pipeline company agrees to provide service and the shipper agrees to pay for the service.
SOFR Secured Overnight Financing Rate
Spot gas purchases The purchase of natural gas on a short-term basis.
Stock acquisitions Investments in corporations.
Unbundled service A service that has been separated from other services, with rates charged that reflect only the cost of the separated service.
Utica Shale A Middle Ordovician-age geological formation lying several thousand feet below the Marcellus Shale in the Appalachian region of the United States, including much of Ohio, Pennsylvania, West Virginia and southern New York.
VEBA Voluntary Employees’ Beneficiary Association
WNA Weather normalization adjustment; an adjustment in utility rates which adjusts customer rates to allow a utility to recover its normal operating costs calculated at normal temperatures. If temperatures during the measured period are warmer than normal, customer rates are adjusted upward in order to recover projected operating costs. If temperatures during the measured period are colder than normal, customer rates are adjusted downward so that only the projected operating costs will be recovered.
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For the Fiscal Year Ended September 30, 2024
| CONTENTS | ||||||||
| Page | ||||||||
| Part I | ||||||||
| ITEM 1 | ||||||||
| ITEM 1A | ||||||||
| ITEM 1B | ||||||||
| ITEM 1C | ||||||||
| ITEM 2 | ||||||||
| ITEM 3 | ||||||||
| ITEM 4 | ||||||||
| Part II | ||||||||
| ITEM 5 | ||||||||
| ITEM 6 | ||||||||
| ITEM 7 | ||||||||
| ITEM 7A | ||||||||
| ITEM 8 | ||||||||
| ITEM 9 | ||||||||
| ITEM 9A | ||||||||
| ITEM 9B | ||||||||
| ITEM 9C | ||||||||
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| Part III | ||||||||
| ITEM 10 | ||||||||
| ITEM 11 | ||||||||
| ITEM 12 | ||||||||
| ITEM 13 | ||||||||
| ITEM 14 | ||||||||
| Part IV | ||||||||
| ITEM 15 | ||||||||
| ITEM 16 | ||||||||
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PART I
| Item 1 | Business | ||||
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, 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, 2024, Seneca had proved developed and undeveloped reserves of 4,751,762 MMcf of natural gas and 193 Mbbl of oil.
2. The Pipeline and Storage segment operations are carried out by National Fuel Gas Supply Corporation, a Pennsylvania corporation, and Empire Pipeline, Inc., 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, a Pennsylvania limited liability company. Through these subsidiaries, Midstream Company builds, owns and operates gathering facilities in the Appalachian region.
4. The Utility segment operations are carried out by National Fuel Gas Distribution Corporation, a New York corporation. Distribution Corporation provides natural gas utility services to approximately 755,000 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.
No single customer, or group of customers under common control, accounted for more than 10% of the Company’s consolidated revenues in 2024.
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.
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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 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 incurred a net loss of $164.0 million in 2024.
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 $79.7 million in 2024.
The Pipeline and Storage segment generated approximately 34% of its revenues in 2024 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.
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The Gathering Segment
The Gathering segment contributed net income of $106.9 million in 2024.
The Gathering segment generated approximately 94% of its revenues in 2024 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 $57.1 million in 2024.
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 $2.2 million in 2024.
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 Exploration and Production 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 2024, the Utility segment purchased 68.8 Bcf of gas (including 66.2 Bcf for delivery to retail customers and 2.6 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 42% of these purchases. Purchases of gas in the spot market (contracts of one month or less) accounted for 58% of the Utility segment’s 2024 purchases. Purchases from DTE Energy Trading, Inc. (31%), Vitol, Inc. (18%), EQT Energy, LLC (8%), Emera Energy Services, Inc. (8%), Chevron Natural Gas (6%), and Tenaska Marketing Ventures (6%) accounted for nearly 77% of the Utility segment’s 2024 gas purchases. No other producer or supplier provided the Utility segment with more than 5% of its gas requirements in 2024. 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, and electrification technologies. Management believes that the reliability and affordability of natural gas support its competitive position relative to electrification and other energy sources.
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.
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Competition: The Exploration and Production Segment
The Exploration and Production segment competes with major integrated and other independent natural gas producers and marketers with respect to the sale of natural gas and, in some cases, the acquisition, exploration and development of mineral rights and leasehold interests.
Seneca strives to distinguish itself amongst its competition by capturing capital efficiencies across its large, contiguous operating footprint in Appalachia and integrated with National Fuel’s Gathering segment operations. Additionally, Seneca is the primary operator on its properties, optimizes technology used for both exploration and development activities, maintains a portfolio of firm transportation and physical firm sales contracts and enters into financial hedges to protect cash flows through commodity price cycles.
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 its 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 commercial and industrial customers are served by 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
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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 adjustment (WNA). Prior to October 2023, the weather impact on cash flow in the Utility segment was mitigated by a WNA solely in its New York rate jurisdiction. However, effective October 2023, the weather impact on cash flow in the Utility segment is also mitigated by a WNA 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 WNA, 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, 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.
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Human Capital
The Company aims to attract the best employees, and to retain those employees through offering competitive benefits and compensation packages, and career development and training opportunities in a safe, inclusive and productive work environment. Human capital measures and objectives that the Company focuses on in managing its business are outlined below. 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. 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 2,311 full-time employees at September 30, 2024.
As of September 30, 2024, 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 and is currently negotiating renewal of those agreements. Additionally, the Company has agreements 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 and salaried variable pay programs 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 4.8% (not including retirements), which is a significant improvement from last year’s voluntary attrition rate of 8.7%. The Company continues to actively monitor employee metrics, including attrition rate, as an indicator of management of and responsiveness to human capital matters.
No Work Stoppages
During fiscal 2024, the Company did not incur any work stoppages (strikes or lockouts) and therefore experienced zero idle days for the fiscal year.
Employee Benefits, Compensation and Development
To attract employees and meet the needs of the Company’s workforce, the Company offers market-competitive benefits packages and compensation to employees of its subsidiaries. The Company’s benefits package options and career development opportunities may vary depending on type of employee and date of hire. Benefits packages may include healthcare benefits, financial and retirement benefits, insurance benefits, and lifestyle benefits. Additionally, the Company 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 corporate responsibility and sustainability objectives of the Company’s business segments. This meaningful investment illustrates the Company’s view that attracting, retaining and motivating our employees is integral to the Company’s success.
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The Company provides its employees with professional development and training resources to enhance their careers within the Company, which, depending on employee type, may include the following: (i) tuition aid program; (ii) sponsorship for professional licensing; (iii) corporate and technical training programs; (iv) continuous talent review and succession planning; and (v) professional development and cross-training discussions encouraged through annual performance reviews and career development discussions.
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 its adoption of specific diversity and inclusion performance goals as part of the Company’s executive compensation and salaried variable pay programs, 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.
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Executive Officers of the Company as of November 15, 2024(1)
Name and Age (as of November 15, 2024) | Current Company Positions and Other Material Business Experience During Past Five Years | |||||||
David P. Bauer (55) | Chief Executive Officer of the Company since July 2019. | |||||||
Donna L. DeCarolis (65) | President of Distribution Corporation since February 2019. | |||||||
Ronald C. Kraemer (68) | Chief Operating Officer of the Company since March 2021, President of Supply Corporation since July 2019 and President of Empire since August 2008. | |||||||
Timothy J. Silverstein (41) | Treasurer and Chief Financial Officer of the Company since May 2023. Treasurer of Seneca Resources Company since May 2023. Treasurer of Distribution Corporation, Supply Corporation, Empire and Midstream Company since July 2021. Mr. Silverstein previously served as Assistant Treasurer of Distribution Corporation, Supply Corporation and Empire from April 2020 through June 2021. General Manager of Finance from April 2019 through March 2020. | |||||||
Elena G. Mendel (58) | Controller and Chief Accounting Officer of the Company since July 2019. Controller of Distribution Corporation, Supply Corporation, Empire, and Midstream Company since July 2019. | |||||||
Martin A. Krebs (54) | Chief Information Officer of the Company since December 2018 and Senior Vice President of Distribution Corporation since May 2023. | |||||||
Michael W. Reville (65) | General Counsel and Secretary of the Company since April 2023 and Senior Vice President of Distribution Corporation since May 2020. Mr. Reville previously served as General Counsel of Distribution Corporation from April 2015 through March 2023. Secretary of Distribution Corporation from May 2020 through March 2023. Vice President of Distribution Corporation from April 2015 through April 2020. | |||||||
Justin I. Loweth (46) | President of Midstream Company since April 2022 and President of Seneca Resources Company since May 2021. Mr. Loweth previously served as Senior Vice President of Seneca Resources Company from October 2017 through April 2021. | |||||||
(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.
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| Item 1A | Risk Factors | ||||
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, subject to certain exceptions, the Company must meet an interest coverage test under its 1974 indenture. In light of impairments recognized in fiscal 2024, the Company expects to be precluded from issuing incremental long-term debt from January 1, 2025 to June 13, 2025, the maturity date of the Company’s remaining indebtedness outstanding under the 1974 indenture. However, to the extent a need arises to issue such incremental long-term debt, the Company expects to be able to place future principal and interest payments in trust for the benefit of bondholders pursuant to the terms of the 1974 indenture. Depositing the future principal and interest payments in trust would effectively relieve the Company from its obligations to comply with the 1974 indenture’s restrictions, including those on the issuance of incremental long-term debt.
The Company’s short-term bank loans, commercial paper, and borrowings under the Term Loan Agreement, entered into on February 14, 2024 with six lenders (the “Term Loan Agreement”), are in the form of floating rate debt or debt that may have rates fixed for short periods of time (up to six months), 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, commercial paper, and borrowings under its Term Loan Agreement, 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.
The regulatory, legislative, consumer behaviors and capital access developments related to climate change may adversely affect operations and financial results.
The laws, regulations and other initiatives to address climate change may impact the Company’s financial results. It is not possible at this time to determine whether changes in the federal administration may change the regulatory focus and/or implementation of rules relating to climate change. 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
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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, carbon tax, or other similar mechanisms 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 waste emissions charge that is expected to be applicable to the annual methane emissions of certain oil and gas facilities, above specified methane intensity thresholds, for emissions reported to the U.S. EPA for 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 CLCPA, 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 Part II, Item 7, 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.
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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 and development 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 and 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, 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
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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 from time to time. 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 availability of and 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 substantial portion of future sales that are based on indexed prices utilizing the physical sale counterparty 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 or sustained high natural gas prices relative to other sources of energy 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 natural 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 natural 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.
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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 delivery revenues, particularly in the Company’s Pennsylvania service territory where delivery revenues are not protected by a revenue decoupling mechanism. 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, fixed price natural gas sale commitments, as well as its foreign exchange transactions.
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 natural gas 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 price hedges, including natural gas hedges and foreign exchange 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, natural gas 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 guidelines. 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.
We may be subject to risks related to increased federal oversight and regulation of the over-the-counter derivatives markets and certain entities that participate in those markets. For discussion of these risks, 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
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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 exploration and production 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 commodity pricing (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 will 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 and ending not later than June 13, 2025, the maturity date of the Company’s remaining indebtedness outstanding under its 1974 indenture. 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 recorded a pre-tax impairment under the ceiling test during the quarter ended June 30, 2024 in the amount of $200.7 million, and during the quarter ended September 30, 2024 in the amount of $263.0 million. Looking ahead, the first day of the month Henry Hub spot price for natural gas in October and
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November 2024 was $2.66 per MMBtu and $1.87 per MMBtu, respectively. Given the October and November prices, and the expected replacement of higher gas prices with lower gas prices in the historical 12-month average that will be used in the ceiling test calculation at December 31, 2024, the Company expects to record a ceiling test impairment for the quarter ending December 31, 2024, and could record additional ceiling test impairments in fiscal 2025.
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.
Attacks on or disruption of the Company’s information technology and operational technology systems, including third party attempts to breach the Company’s network security, or other cybersecurity threats and incidents could adversely affect the Company’s operations and 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
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systems, some of which are dependent on third party business partners, 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 and those of our third party business partners are subject to cybersecurity threats and attacks, including attempts by others to gain unauthorized access, or to otherwise introduce malicious software or software vulnerabilities. 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 and accessibility 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 controls to maintain and protect its information technology and operational technology systems, the Company may be vulnerable to disruptions, cybersecurity incidents, 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. Cybersecurity threats or 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, malicious alteration or corruption of data or systems, costs related to remediation or the payment of ransom, and litigation including individual claims or consumer class actions, commercial litigation, administrative, and civil or criminal investigations or actions, regulatory intervention and sanctions or fines, investigation and remediation costs and reputational harm. Significant expenditures may be required to remedy system disruptions, cybersecurity incidents, or breaches or address cybersecurity threats, including restoration of customer service and enhancement of information technology and operational technology systems. We have invested in the protection of data and information technology, and actively work to enhance our business continuity and disaster recovery capabilities; however, there can be no assurance that our efforts will be successful.
The Company seeks to prevent, detect and investigate cybersecurity incidents, but in some cases the Company might be unaware of an incident or its magnitude and effects. In addition to existing risks and cybersecurity threats, the adoption of new technologies, including generative artificial intelligence tools, may increase the Company’s exposure to data breaches and cybersecurity incidents or the Company’s ability to detect and remediate effects of breaches and cybersecurity incidents. The Company has experienced attempts to breach its network security and cybersecurity threats 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 occurrences and 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 and related investments in supporting facilities 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
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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, as well as the development of related exploration and production assets, is significant and often uncertain. New wells and related assets may not be successful 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 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 may disrupt the Company’s supply chain, workforce, 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, 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. For example, the Company is currently negotiating with two collective bargaining units in New York for agreements that expire in February 2025. 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, impact the Company’s ability to fully execute operational plans, and have a material adverse effect on the Company’s results of operations and financial condition.
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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. In addition, judicial decisions limiting the authority of regulatory agencies, or decisions impacting current regulations and policies implemented by such agencies, could create uncertainty regarding the regulatory landscape and impact the Company’s ability to plan for future investments.
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,
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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. In addition, estimates of the Company’s potential liabilities relating to current or former natural gas and oil properties, including the costs associated with plugging and abandoning wells, may be incorrect, and actual plugging and abandonment expenses may vary substantially from the Company’s estimates.
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.
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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, including the crediting of employee benefit plan trust income to ratepayers by reducing delivery rates and customer revenues, and the refund of regulatory liability balances. The application of current rate treatment is subject to change 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.
| Item 1B | Unresolved Staff Comments | ||||
None.
| Item 1C | Cybersecurity | ||||
Overview
The Company, as an owner and operator of critical energy infrastructure, is subject to evolving risks from cybersecurity threats. The Company increasingly relies on technology to optimize its business functions. The Company maintains a cybersecurity program that is designed to assess, identify and manage material risks from cybersecurity threats and includes internal and external controls, risk assessments, incident simulations, employee trainings and corporate policies.
Governance
The Board of Directors retains risk oversight of significant risks from cybersecurity threats that might arise from the Company’s operations. An important aspect of the Board’s oversight role is the enterprise risk management process, under which enterprise-wide risks have been identified and assessed, which the Board is
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briefed on quarterly at the Audit Committee meetings. Information security risks are identified and assessed as part of the Company’s enterprise risk management process.
The Corporate Information Security Steering Committee (“CISSC”) is responsible for assessing and managing the Company’s material risks from cybersecurity threats. The CISSC meets quarterly to discuss emerging information security risks and the Company’s corresponding mitigation and defense efforts. Led by the Company’s Chief Information Officer (“CIO”) and Chief Information Security Officer (“CISO”), the CISSC is composed of Information Security (“InfoSec”) professionals, leadership from key departments and the Company’s senior management. The Company’s CIO has over 30 years of experience in the field of information systems and cybersecurity and the CISO has over 20 years of experience in cyber and physical security and leads an experienced security and networking team. The CISO regularly provides information security updates to the Board.
The InfoSec team promotes security awareness through personnel training and regularly reviewing internal information security policies, monitoring for anomalous behavior, investigating potential security events, attempting to mitigate security vulnerabilities, and assisting business partners on cybersecurity matters. The InfoSec team meets regularly with key Information Technology and Operation Technology leadership to discuss potential cybersecurity threats and review alerts.
The Company’s Incident Response Team, made up primarily of the General Counsel, CIO, CISO, Legal, and InfoSec directors, reviews the Company’s Information Security Incident Response Plan (“ISIRP”) annually. As part of the ISIRP, the Company has also established a cybersecurity incident escalation process whereby potential cybersecurity incidents are identified, monitored, assessed, and escalated to our Disclosure Committee, as appropriate.
Risk Management and Strategy
The Company has established an information security program (the “Information Security Program”) that is designed to assess, identify and manage material risks from cybersecurity threats. The Information Security Program is designed to align to the Cybersecurity Framework published by the National Institute of Standards and Technology (“NIST”). However, this does not mean that the Company’s Information Security Program meets any particular technical standards, specifications or requirements, but rather that the Company uses NIST and other cybersecurity standards as a guide to help us identify, assess and manage cybersecurity risks relevant to its business. The Information Security Program is centralized under the CISO, who reports to the CIO. The Company periodically reevaluates its Information Security Program to assess whether planned initiatives are appropriate and to assess risk mitigation and defense efforts. The Company maintains cybersecurity insurance coverage.
The Company conducts regular cybersecurity vulnerability assessments that are designed to identify potential risks and opportunities for cybersecurity improvement. The Company also conducts cybersecurity incident simulations annually and undergoes internal and external audits of our processes. The Company participates in industry organizations, engages third-party service providers, and maintains close working relationships with law enforcement agencies to help us identify and address risks from cybersecurity threats.
The Company provides employees with least privilege access, and contractors with independent access to Company systems, which is audited regularly. Employees and contractors receive regular information security training, including malicious email testing, “phishing” awareness training and targeted cybersecurity training.
The Company engages multiple independent cybersecurity consultants throughout the year to conduct assessments of the Company’s technology and risks from cybersecurity threats. On occasion, the Company voluntarily participates in separate assessments focused on different information security issues performed by various U.S. federal agencies, including the Cybersecurity and Infrastructure Security Agency, the Transportation Security Administration, the Department of Homeland Security and the FERC. The Company also annually performs the NYPSC review of third-party attestation as it relates to Case 13-M-0178 (protection of personally identifiable customer information).
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To date, the Company does not believe risks from cybersecurity threats, including as a result of previous cybersecurity incidents, have materially affected or are reasonably likely to materially affect the Company’s business strategy, results of operations or financial condition. However, because the Company operates in the area of critical infrastructure, as defined under federal law and by the Transportation Security Administration, the Company has been and will continue to be the target of cybersecurity attacks from time to time. As such, the Company cannot guarantee that future cybersecurity incidents will not materially affect the Company’s business strategy, results of operations and financial condition. For further discussion regarding cybersecurity risks and their impact on our business strategy, results of operations and financial condition, see the risk factor entitled “Attacks on or disruption of the Company’s information technology and operational technology systems, including third party attempts to breach the Company’s network security, or other cybersecurity threats and incidents could adversely affect the Company’s operations and financial results” under the heading “Risk Factors” in Item 1A of this Annual Report.
| Item 2 | Properties | ||||
General Information on Facilities
The net investment of the Company in property, plant and equipment was $7.3 billion at September 30, 2024. The Exploration and Production segment constitutes 32.5% of this investment, and is primarily located in the Appalachian region of the United States. Approximately 54.3% 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 13.1% of the Company’s investment in net property, plant and equipment, and is located in northwestern and central Pennsylvania. The remaining 0.1% of the Company’s net investment in property, plant and equipment falls within All Other and Corporate operations. 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 $1.8 billion, or 33.2%, since September 30, 2019. The five-year increase is net of impairments of assets recorded in 2020, 2021 and 2024 (pre-tax amounts of $449 million, $76 million and $519 million, respectively).
The Exploration and Production segment had a net investment in property, plant and equipment of $2.4 billion at September 30, 2024 consisting primarily of capitalized costs relating to exploration and production activities, the components of which are disclosed in Item 8, Note N — Supplementary Information for Exploration and Production Activities.
The Pipeline and Storage segment had a net investment of $2.1 billion in property, plant and equipment at September 30, 2024. Transmission pipeline represents 36% of this segment’s total net investment and includes 2,233 miles of pipeline utilized to move large volumes of gas throughout its service area. Storage facilities represent 14% of this segment’s total net investment and consist of 384 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 $81.2 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 260,088 installed horsepower that represent 32% 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 2024 peak day sendout for transportation service of 2,304 MMcf, which occurred on January 14, 2024. Withdrawals from storage of 590 MMcf provided approximately 26% of the requirements on that day.
The Gathering segment had a net investment of $1.0 billion in property, plant and equipment at September 30, 2024. Gathering lines and related compressor stations represent substantially all of this segment’s total net investment, including 390 miles of pipelines utilized to move Appalachian production
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(including Marcellus and Utica shales) to various transmission pipeline receipt points. The Gathering segment has 23 compressor stations with 122,406 installed horsepower.
The Utility segment had a net investment in property, plant and equipment of $1.8 billion at September 30, 2024. The net investment in its gas distribution network (including 15,090 miles of distribution pipeline) and its service connections to customers represent approximately 50% and 31%, respectively, of the Utility segment’s net investment in property, plant and equipment at September 30, 2024.
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 exploration and production activities is included in Item 8, Note N — Supplementary Information for Exploration and Production Activities. Note N sets forth proved developed and undeveloped reserve information for Seneca. The September 30, 2024, 2023 and 2022 reserves shown in Note N are valued using an unweighted arithmetic average of first day of the month commodity price 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 gas reserves year over year.
Seneca’s proved developed and undeveloped natural gas reserves increased from 4,535 Bcf at September 30, 2023 to 4,752 Bcf at September 30, 2024. This increase is attributed to extensions and discoveries of 602 Bcf and revisions of previous estimates of 7 Bcf, partially offset by production of 392 Bcf. Upward revisions of 145 Bcf are mainly attributed to positive performance improvements, changes to the booked lateral length and optimized development layout. The additions and upward revisions were partially offset by downward revisions of 138 Bcf from the removal of nine PUD locations related to schedule 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 natural gas reserves increased from 4,171 Bcf at September 30, 2022 to 4,535 Bcf at September 30, 2023. This increase was 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 were 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.
At September 30, 2024, the Company’s Exploration and Production segment had delivery commitments for natural gas production of 1,896 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.
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The following is a summary of certain oil and gas information taken from Seneca’s records.
Production
| For The Year Ended September 30 | ||||||||||||||||||||||||||
| 2024 | 2023 | 2022 | ||||||||||||||||||||||||
| United States | ||||||||||||||||||||||||||
| Appalachian Region | ||||||||||||||||||||||||||
| Average Sales Price per Mcf of Gas | $ | 1.88 | (1) | $ | 2.78 | (1) | $ | 5.03 | (1) | |||||||||||||||||
| Average Sales Price per Barrel of Oil | N/M | N/M | N/M | |||||||||||||||||||||||
| Average Sales Price per Mcf of Gas (after hedging) | $ | 2.44 | $ | 2.55 | $ | 2.69 | ||||||||||||||||||||
| Average Sales Price per Barrel of Oil (after hedging) | N/M | N/M | N/M | |||||||||||||||||||||||
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | $ | 0.69 | (1) | $ | 0.68 | (1) | $ | 0.68 | (1) | |||||||||||||||||
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | 1,072 | (1) | 1,020 | (1) | 936 | (1) | ||||||||||||||||||||
West Coast Region (2) | ||||||||||||||||||||||||||
| Average Sales Price per Mcf of Gas | N/A | N/A | $ | 10.03 | ||||||||||||||||||||||
| Average Sales Price per Barrel of Oil | N/A | N/A | $ | 94.06 | ||||||||||||||||||||||
| Average Sales Price per Mcf of Gas (after hedging) | N/A | N/A | $ | 10.03 | ||||||||||||||||||||||
| Average Sales Price per Barrel of Oil (after hedging) | N/A | N/A | $ | 70.53 | ||||||||||||||||||||||
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | N/A | N/A | $ | 4.83 | ||||||||||||||||||||||
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | N/A | N/A | 39 | |||||||||||||||||||||||
| Total Company | ||||||||||||||||||||||||||
| Average Sales Price per Mcf of Gas | $ | 1.88 | $ | 2.78 | $ | 5.05 | ||||||||||||||||||||
| Average Sales Price per Barrel of Oil | N/M | N/M | $ | 94.10 | ||||||||||||||||||||||
| Average Sales Price per Mcf of Gas (after hedging) | $ | 2.44 | $ | 2.55 | $ | 2.71 | ||||||||||||||||||||
| Average Sales Price per Barrel of Oil (after hedging) | N/M | N/M | $ | 70.80 | ||||||||||||||||||||||
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | $ | 0.69 | $ | 0.68 | $ | 0.81 | ||||||||||||||||||||
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | 1,072 | 1,020 | 966 | |||||||||||||||||||||||
N/M Sales price amounts are considered not meaningful as oil production is insignificant.
(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, 2024, 2023 and 2022) contributed 645 MMcfe, 521 MMcfe and 574 MMcfe of daily production in 2024, 2023 and 2022, respectively. The average lifting costs (per Mcfe) were $0.72 in 2024, $0.73 in 2023 and $0.71 in 2022. The Utica Shale fields (which exceed 15% of total reserves at September 30, 2024, 2023 and 2022) contributed 423 MMcfe, 495 MMcfe and 357 MMcfe of daily production in 2024, 2023 and 2022, respectively. The average lifting costs (per Mcfe) were $0.64 in 2024, $0.62 in 2023 and $0.63 in 2022.
(2)West Coast region properties were sold at June 30, 2022. Information for the years ended September 30, 2023 and 2024 is not applicable (N/A) as a result of the sale.
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Productive Wells
| Appalachian Region | |||||
| At September 30, 2024 | Gas | ||||
| Productive Wells — Gross | 1,043 | ||||
| Productive Wells — Net | 928 | ||||
Developed and Undeveloped Acreage
| At September 30, 2024 | Appalachian Region | |||||||
| Developed Acreage | ||||||||
| — Gross | 673,978 | |||||||
| — Net | 661,856 | |||||||
| Undeveloped Acreage | ||||||||
| — Gross | 701,123 | |||||||
| — Net | 659,234 | |||||||
| Total Developed and Undeveloped Acreage | ||||||||
| — Gross | 1,375,101 | |||||||
| — Net | 1,321,090 | (1) | ||||||
(1)Of the 1,321,090 Total Developed and Undeveloped Net Acreage in the Appalachian region as of September 30, 2024, there are a total of 1,249,213 net acres in Pennsylvania. Of the 1,249,213 total net acres in Pennsylvania, shale development in the Marcellus, Utica or Geneseo shales has occurred on approximately 144,551 net acres, or 12% 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, 2024, the aggregate amounts of gross undeveloped acreage expiring under lease in the next three years and thereafter are as follows: 1,547 acres in 2025 (1,388 net acres), 13,650 acres in 2026 (13,503 net acres), 9,267 acres in 2027 (8,398 net acres) and 204,655 acres thereafter (197,901 net acres). The remaining 472,004 gross acres (438,044 net acres) represent non-expiring oil and gas rights owned by the Company. Of the acreage that is currently scheduled to expire in 2025, 2026 and 2027, Seneca has 633.7 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.
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Drilling Activity
| Productive | Dry | ||||||||||||||||||||||||||||||||||
| For the Year Ended September 30 | 2024 | 2023 | 2022 | 2024 | 2023 | 2022 | |||||||||||||||||||||||||||||
| United States | |||||||||||||||||||||||||||||||||||
| Appalachian Region | |||||||||||||||||||||||||||||||||||
| Net Wells Completed | |||||||||||||||||||||||||||||||||||
| — Exploratory | — | — | — | — | — | — | |||||||||||||||||||||||||||||
| — Development(1) | 34.00 | 34.25 | 43.00 | — | 0.50 | 2.50 | |||||||||||||||||||||||||||||
| West Coast Region | |||||||||||||||||||||||||||||||||||
| Net Wells Completed | |||||||||||||||||||||||||||||||||||
| — Exploratory | — | — | — | — | — | — | |||||||||||||||||||||||||||||
| — Development | — | — | 23.00 | — | — | — | |||||||||||||||||||||||||||||
| Total Company | |||||||||||||||||||||||||||||||||||
| Net Wells Completed | |||||||||||||||||||||||||||||||||||
| — Exploratory | — | — | — | — | — | — | |||||||||||||||||||||||||||||
| — Development | 34.00 | 34.25 | 66.00 | — | 0.50 | 2.50 | |||||||||||||||||||||||||||||
(1)Fiscal 2023 and 2022 Appalachian region dry wells include 0.5 and 2.5 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 and 2022 after the Company determined it would not continue development activities.
Present Activities
| At September 30, 2024 | Appalachian Region | ||||
| Wells in Process of Drilling(1) | |||||
| — Gross | 48.00 | ||||
| — Net | 42.00 | ||||
(1)Includes wells awaiting completion.
| Item 3 | Legal Proceedings | ||||
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.”
| Item 4 | Mine Safety Disclosures | ||||
Not Applicable.
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PART II
| Item 5 | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | ||||
At September 30, 2024, there were 8,318 registered shareholders of Company common stock. The common stock is listed and traded on the New York Stock Exchange under the trading symbol “NFG”. Information regarding the market for the Company’s common equity and related stockholder matters appears under Item 12 at Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters and Item 8 at Note H — Capitalization and Short-Term Borrowings.
On July 1, 2024, the Company issued a total of 8,060 unregistered shares of Company common stock to non-employee directors of the Company then serving on the Board of Directors of the Company (or, in the case of non-employee directors who elected to defer receipt of such shares pursuant to the Company’s Deferred Compensation Plan for Directors and Officers (the “DCP”), to the DCP trustee), consisting of 806 shares per director. All of these unregistered shares were issued under the Company’s 2009 Non-Employee Director Equity Compensation Plan as partial consideration for such directors’ services during the quarter ended September 30, 2024. The Company issued an additional 708 unregistered shares in the aggregate on July 14, 2024 pursuant to the dividend reinvestment feature of the DCP, to the six non-employee directors who participate in the DCP. These transactions were exempt from registration under Section 4(a)(2) of the Securities Act of 1933, as transactions not involving a public offering.
Issuer Purchases of Equity Securities
| Period | Total Number of Shares Purchased(a) | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Share Repurchase Plans or Programs | Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under Share Repurchase Plans or Programs(b) | ||||||||||||||||||||||
July 1-31, 2024 | 280,175 | $ | 56.57 | 266,727 | $ | 156,419,314 | ||||||||||||||||||||
Aug. 1-31, 2024 | 205,588 | $ | 58.93 | 192,781 | $ | 145,064,061 | ||||||||||||||||||||
Sept. 1-30, 2024 | 173,614 | $ | 60.06 | 160,099 | $ | 135,437,277 | ||||||||||||||||||||
| Total | 659,377 | $ | 58.52 | 619,607 | $ | 135,437,277 | ||||||||||||||||||||
(a)Represents (i) shares of common stock of the Company purchased with Company “matching contributions” for the accounts of participants in the Company’s 401(k) plans, (ii) shares of common stock of the Company, if any, tendered to the Company by holders of stock-based compensation awards for the payment of applicable withholding taxes, and (iii) shares of common stock of the Company purchased on the open market pursuant to the Company’s share repurchase program. Of the 39,770 shares purchased other than through a publicly announced share repurchase program, 39,090 were purchased for the Company’s 401(k) plans and 680 were purchased as a result of shares tendered to the Company by holders of stock-based compensation awards.
(b)On March 8, 2024, the Company’s Board of Directors authorized the repurchase of up to $200 million of shares of the Company’s common stock. The calculation of the dollar value of shares remaining available for purchase excludes excise taxes and brokerage fees paid by the Company in connection with the repurchase program which in the aggregate totaled $0.6 million from the beginning of the program to September 30, 2024. Repurchases may be made from time to time in the open market or through privately negotiated transactions, including through the use of trading plans intended to qualify under SEC Rule 10b5-1, in accordance with applicable securities laws and other restrictions. The repurchase program has no expiration date. In connection with its authorization of the repurchase program, the Board terminated the Company’s prior repurchase program, under which 6,971,019 shares had remained available for purchase. The Company had not repurchased shares under the prior program since September 2008.
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Performance Graph
The following graph compares the Company’s common stock performance with the performance of the S&P 500 Index, the S&P Mid Cap 400 Gas Utility Index and the S&P 1500 Oil & Gas Exploration & Production Index for the period September 30, 2019 through September 30, 2024. The graph assumes that the value of the investment in the Company’s common stock and in each index was $100 on September 30, 2019 and that all dividends were reinvested.
| 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | |||||||||||||||
| National Fuel | $100 | $93 | $125 | $150 | $131 | $159 | ||||||||||||||
| S&P 500 Index | $100 | $117 | $152 | $128 | $156 | $212 | ||||||||||||||
| S&P Mid Cap 400 Gas Utility Index (S4GASU) | $100 | $72 | $88 | $90 | $81 | $97 | ||||||||||||||
| S&P 1500 Oil & Gas Exp & Prod Index (S15OILP) | $100 | $57 | $134 | $200 | $235 | $224 | ||||||||||||||
Source: Bloomberg
The performance graph above is furnished and not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and will not be incorporated by reference into any registration statement filed under the Securities Act of 1933 unless specifically identified therein as being incorporated therein by reference. The performance graph is not soliciting material subject to Regulation 14A.
| Item 6 | (Reserved) | ||||
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| Item 7 | Management’s Discussion and Analysis of Financial Condition and Results of Operations | ||||
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 exploration and production development activities are focused primarily in the Marcellus and Utica shales, geological formations that are present in the Appalachian region of the United States. 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. In addition to expansion projects, the Company continues to focus on the ongoing modernization of its regulated Pipeline and Storage and Utility assets. The Company reports financial results for four business segments: Exploration and Production, Pipeline and Storage, Gathering, and Utility.
Fiscal 2024 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) details regarding the status of Supply Corporation and Empire’s Northern Access project; (b) 2024 and projected 2025 funding for the Company’s pension and other post-retirement benefits; (c) disclosures and tables concerning market risk sensitive instruments; (d) rate matters in the Company’s New York, Pennsylvania and FERC-regulated jurisdictions; (e) environmental matters; and (f) 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 2024 and fiscal 2023. 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 2022 to fiscal 2023 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, 2023, filed with the SEC on November 17, 2023.
The Company’s Exploration and Production segment continues to grow, as evidenced by a 5% growth in proved reserves from the prior year to a total of 4,753 Bcfe at September 30, 2024. Production increased 19.8 Bcfe, or 5%, during the fiscal year ended September 30, 2024 to a total of 392.2 Bcfe, and is expected to increase again in fiscal 2025.
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, which is an expansion and modernization 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 (“Transco”) capacity lease, providing access to Mid-Atlantic markets. Supply Corporation filed a Section 7 (c) application with FERC for the project on August 21, 2024. The Tioga Pathway Project has a target in-service date in late calendar 2026 and a preliminary cost estimate of approximately $101 million. The Tioga Pathway Project is discussed in more detail in the Capital Resources and Liquidity section that follows.
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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 approximately $88 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. After settlement negotiations, a Joint Proposal was filed with the NYPSC on September 9, 2024, that establishes a three-year rate plan allowing for an $86 million increase in annual revenue requirement over three years, with the first-year impact of $57 million in fiscal 2025 and the remainder in fiscal 2026 and fiscal 2027. It also includes standard make-whole language allowing the recovery of authorized revenues between September 30, 2024 and the start of new rates. The Joint Proposal remains subject to final NYPSC approval. In addition, Supply Corporation filed an NGA Section 4 rate case at FERC on July 31, 2023. Settlement rates became effective on February 1, 2024 under a settlement that was approved by FERC without modification on June 11, 2024, and which is estimated to increase Supply Corporation’s revenues by approximately $56 million on an annual basis. For further discussion of Distribution Corporation and Supply Corporation rate matters, refer to the Rate Matters section below.
As discussed in the following Critical Accounting Estimates section, the Company uses the full cost method of accounting for determining the book value of its exploration and production properties and that book value is subject to a quarterly ceiling test. The Company recorded cumulative impairment charges under the ceiling test during fiscal 2024 of $463.7 million ($336.4 million after-tax). Looking ahead, the first day of the month Henry Hub spot price for natural gas in October 2024 and November 2024 was $2.66 per MMBtu and $1.87 per MMBtu, respectively. Given these prices, and the expected replacement of higher gas prices with lower gas prices in the historical 12-month average that will be used in the ceiling test calculation for the next quarter, the Company expects to experience a ceiling test impairment for the quarter ending December 31, 2024, and could record additional ceiling test impairments in fiscal 2025. Please refer to the Critical Accounting Estimates section below for a sensitivity analysis concerning commodity price changes.
The Company also recorded an impairment charge of $46.1 million ($33.8 million after-tax) in its Pipeline and Storage segment at September 30, 2024 to write down the value of certain assets associated with Supply Corporation and Empire’s Northern Access project. Additional details related to the Northern Access project are discussed further in the Other Matters section below.
From a financing perspective, given the significant impairments recorded during fiscal 2024 discussed above, under its existing indenture covenants, the Company would be precluded from issuing incremental long-term debt beginning in January 2025, for a period likely to extend to June 2025, when the remaining long-term debt outstanding under the Company’s 1974 indenture matures. However, the 1974 indenture would not prevent the Company from issuing new long-term debt to replace existing long-term debt, including borrowings under the Term Loan Agreement, or from issuing additional short-term debt. To the extent a need arises to issue incremental long-term debt, the Company expects to be able to place future principal and interest payments in trust for the benefit of bondholders pursuant to the terms of the 1974 indenture. Depositing the future principal and interest payments in trust would effectively relieve the Company from its obligations to comply with the 1974 indenture’s restrictions, including those on the issuance of incremental long-term debt.
In February 2024, eleven lenders in the syndicate of twelve banks under the Credit Agreement consented to an extension of the maturity date of the Credit Agreement from February 26, 2027 to February 25, 2028. In May 2024, three of the lenders in the syndicate assumed the commitments of the sole non-extending lender. As a result, the Company has aggregate commitments available under the Credit Agreement of $1.0 billion to February 25, 2028.
On February 14, 2024, the Company entered into the Term Loan Agreement with six lenders. The Term Loan Agreement established a $300 million unsecured committed delayed draw term loan credit facility with a maturity date of February 14, 2026. In April 2024, the Company elected to draw a total of $300 million under the facility. The Company used the proceeds for general corporate purposes, including the redemption of
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outstanding commercial paper. For further discussion of the Term Loan Agreement, refer to the Capital Resources and Liquidity section that follows.
The Company began repurchasing outstanding shares of common stock during the quarter ended March 31, 2024 under a share repurchase program authorized by the Company’s Board of Directors. The program authorizes the Company to repurchase up to an aggregate amount of $200 million of its outstanding common stock in the open market or through privately negotiated transactions. During fiscal 2024, the Company executed transactions to repurchase 1,146,259 shares at an average price of $56.32 per share. With broker fees and excise taxes, the total cost of these repurchases amounted to $65.2 million. These matters are discussed further in the Capital Resources and Liquidity section that follows.
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 2025, including the redemption of two of the Company’s long-term debt maturities totaling $500.0 million that are scheduled to mature in 2025. The Company continues to evaluate these financing needs and options to meet them. Given the current economic conditions, which include continued inflationary pressures, volatile interest rates and a change in administration at the federal level, the cost and/or availability of capital may be impacted, but the Company continues to expect to meet its financing needs.
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 and sustainability, 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 on corporate responsibility and sustainability strategies and initiatives that are of significance to the Company and its stakeholders, and may also make recommendations to the Board regarding these strategies and initiatives.
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 2030 methane intensity reduction targets at each of its businesses, a 2030 absolute greenhouse gas emissions reduction target for the consolidated Company, and 2030 and 2050 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 progress towards the Company’s emissions targets. 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.
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
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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.
Exploration and Development Costs. In the Company’s Exploration and Production segment, 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 after the fiscal 2022 sale of the Company’s California exploration and production properties. 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 properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves 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 commodity 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 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, which are based on current costs, associated with 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 exploration and production properties less accumulated depletion and related deferred income taxes. If the capitalized costs of exploration and production 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. The book value of the exploration and production properties exceeded the ceiling at September 30, 2024 as well as June 30, 2024, resulting in a cumulative non-cash impairment charge of $463.7 million ($336.4 million after-tax) for the year ended September 30, 2024. The 12-month average of the first day of the month price for
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natural gas for each month during 2024, based on the quoted Henry Hub spot price for natural gas, was $2.21 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 2024. Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.) The following table illustrates the sensitivity of the ceiling test calculation to commodity price changes, specifically showing the additional impairment that the Company would have recorded at September 30, 2024 if natural gas prices were $0.25 per MMBtu lower than the average prices used at September 30, 2024 (all amounts are presented after-tax). These calculated amounts are based solely on price changes and do not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates.
| Ceiling Testing Sensitivity to Commodity Price Changes | |||||
| (Millions) | $0.25/MMBtu Decrease in Natural Gas Prices | ||||
Calculated Impairment under Sensitivity Analysis | $ | 579.4 | |||
| Actual Impairment Recorded at September 30, 2024 | 191.4 | ||||
Additional Impairment | $ | 388.0 | |||
Looking ahead, the first day of the month Henry Hub spot price for natural gas in October 2024 and November 2024 was $2.66 per MMBtu and $1.87 per MMBtu, respectively. Given the October and November prices, and the expected replacement of higher gas prices with lower gas prices in the historical 12-month average that will be used in the ceiling test calculation for the next quarter, the Company expects to experience a ceiling test impairment for the quarter ending December 31, 2024, and could record additional ceiling test impairments in fiscal 2025.
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.
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RESULTS OF OPERATIONS
EARNINGS
2024 Compared with 2023
The Company’s earnings were $77.5 million in 2024 compared to earnings of $476.9 million in 2023. The decrease in earnings of $399.4 million was primarily the result of a loss recognized in the Exploration and Production segment compared to earnings in the prior year combined with lower earnings in the Pipeline and Storage segment. Higher earnings in the Utility segment and the Gathering segment, along with a lower loss in the Corporate category, partially offset these decreases. 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 2024:
2024 Events
•Non-cash impairment charges of $473.1 million ($343.2 million after-tax) recorded during 2024 in the Exploration and Production segment, consisting mostly of ceiling test impairment charges of $463.7 million ($336.4 million after-tax). The remaining charges are related to impairments of certain water disposal assets.
•Non-cash impairment charge of $46.1 million ($33.8 million after-tax) recorded during the quarter ended September 30, 2024 in the Pipeline and Storage segment associated with the Northern Access project.
Earnings (Loss) by Segment
| Year Ended September 30 | |||||||||||||||||
| 2024 | 2023 | 2022 | |||||||||||||||
| (Thousands) | |||||||||||||||||
| Exploration and Production | $ | (163,954) | $ | 232,275 | $ | 306,064 | |||||||||||
| Pipeline and Storage | 79,670 | 100,501 | 102,557 | ||||||||||||||
| Gathering | 106,913 | 99,724 | 101,111 | ||||||||||||||
| Utility | 57,089 | 48,395 | 68,948 | ||||||||||||||
| Total Reported Segments | 79,718 | 480,895 | 578,680 | ||||||||||||||
| All Other | (617) | (531) | (9) | ||||||||||||||
| Corporate | (1,588) | (3,498) | (12,650) | ||||||||||||||
| Total Consolidated | $ | 77,513 | $ | 476,866 | $ | 566,021 | |||||||||||
EXPLORATION AND PRODUCTION
Revenues
Exploration and Production Operating Revenues
| Year Ended September 30 | |||||||||||
| 2024 | 2023 | ||||||||||
| (Thousands) | |||||||||||
| Gas Produced in Appalachia (after Hedging) | $ | 955,790 | $ | 948,484 | |||||||
| Other | 5,288 | 9,971 | |||||||||
| Operating Revenues | $ | 961,078 | $ | 958,455 | |||||||
Production
| Year Ended September 30 | |||||||||||
| 2024 | 2023 | ||||||||||
| Gas Production (MMcf) | 392,047 | 372,271 | |||||||||
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Average Prices
| Year Ended September 30 | |||||||||||
| 2024 | 2023 | ||||||||||
| Average Gas Price/Mcf | |||||||||||
| Weighted Average | $ | 1.88 | $ | 2.78 | |||||||
| Weighted Average After Hedging(1) | $ | 2.44 | $ | 2.55 | |||||||
(1)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.
2024 Compared with 2023
Operating revenues for the Exploration and Production segment increased $2.6 million in 2024 as compared with 2023. Gas production revenue after hedging increased $7.3 million primarily due to a 19.8 Bcf increase in gas production offset by a $0.11 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. Partially offsetting this increase, other revenue decreased $4.7 million due to the non-recurrence of temporary capacity release revenue for a portion of this segment’s transportation capacity in 2023.
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.
Earnings
2024 Compared with 2023
The Exploration and Production segment experienced a loss of $164.0 million in 2024, a decrease of $396.3 million from earnings of $232.3 million in 2023. The decrease was primarily attributable to non-cash impairments of assets ($343.2 million), including an aggregate $336.4 million of ceiling test impairments recorded during the quarters ended June 30, 2024 and September 30, 2024 as well as a $6.8 million impairment of certain water disposal assets recorded during the quarter ended September 30, 2024. In conjunction with the ceiling test impairment, there was a $5.8 million earnings reduction associated with the remeasurement of state deferred income taxes. Other factors contributing to the decrease included lower natural gas prices after hedging ($34.0 million) and lower other revenue ($3.7 million), as discussed above. Higher depletion expense ($29.1 million), higher lease operating and transportation expenses ($13.7 million), higher other operating expenses ($8.9 million) and an increase in interest expense ($4.3 million) also reduced earnings. There was also a $4.1 million increase in unrealized losses related to contingent consideration received as part of the California asset sale. These decreases were partially offset by higher natural gas production ($39.8 million) combined with lower other taxes ($3.2 million) and a reduction in income tax expense ($7.3 million). The increase in depletion expense was primarily due to the net increase in production combined with a $0.06 per Mcf increase in the depletion rate. The increase in lease operating and transportation expenses was primarily the result of higher gathering and transportation costs combined with higher workover expenses. The increase in other operating expenses was primarily attributable to recognizing an accrual of plugging and abandonment costs related to certain offshore Gulf of Mexico wells and certain California wells that were sold by Seneca to operators that are now defunct or unable to cover the cost of the abandonment activities. As a result, a portion of the cost of abandoning the wells is expected to revert back to Seneca. Higher personnel costs also contributed to the increase in other operating expenses. The increase in interest expense can largely be attributed to higher average interest rates on intercompany short-term and long-term borrowings, partially offset by lower intercompany long-term debt balances. The decrease in other taxes was primarily attributable to lower Impact Fees in the Appalachian region as the Company moved into a lower rate tier due to lower NYMEX pricing. The reduction in income tax expense was primarily driven by a decrease in pre-tax income and lower state income tax expense. The lower state income taxes were a result of a decrease in Pennsylvania’s state income tax rate from 9.99% in the prior year to 8.99% in the current year, as well as a change in the mix of revenues between state jurisdictions.
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PIPELINE AND STORAGE
Revenues
Pipeline and Storage Operating Revenues
| Year Ended September 30 | |||||||||||
| 2024 | 2023 | ||||||||||
| (Thousands) | |||||||||||
| Firm Transportation | $ | 311,247 | $ | 289,935 | |||||||
| Interruptible Transportation | 653 | 1,290 | |||||||||
| 311,900 | 291,225 | ||||||||||
| Firm Storage Service | 95,931 | 84,960 | |||||||||
| Interruptible Storage Service | 2 | 2 | |||||||||
| 95,933 | 84,962 | ||||||||||
| Other | 4,560 | 3,004 | |||||||||
| $ | 412,393 | $ | 379,191 | ||||||||
Pipeline and Storage Throughput — (MMcf)
| Year Ended September 30 | |||||||||||
| 2024 | 2023 | ||||||||||
| Firm Transportation | 757,407 | 816,484 | |||||||||
| Interruptible Transportation | 1,791 | 2,192 | |||||||||
| 759,198 | 818,676 | ||||||||||
2024 Compared with 2023
Operating revenues for the Pipeline and Storage segment increased $33.2 million in 2024 as compared with 2023. The increase in operating revenues was primarily due to an increase in transportation revenues of $20.7 million, an increase in storage revenues of $11.0 million and an increase in other revenues of $1.5 million. The increase in transportation and storage revenues was primarily attributable to an increase in Supply
Corporation’s transportation and storage rates effective February 1, 2024, in accordance with Supply Corporation’s rate case settlement. The settlement was approved by FERC on June 11, 2024. The increase in other revenues primarily reflects an adjustment to match electric surcharge revenues to electric power costs recorded in operation and maintenance expense. This increase was partially offset by proceeds that were received during the quarter ended September 30, 2023 as a result of a contract buyout that did not recur in the current fiscal year.
Transportation volume decreased by 59.5 Bcf in 2024 as compared with 2023, primarily due to a decrease in volume as a result of lower capacity utilization with certain contract shippers and certain contract expirations, combined with a decline in volume from warmer weather. Volume fluctuations, other than those caused by the addition or termination of contracts, generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.
The 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 2025.
Earnings
2024 Compared with 2023
The Pipeline and Storage segment’s earnings in 2024 were $79.7 million, a decrease of $20.8 million when compared with earnings of $100.5 million in 2023. The decrease in earnings was primarily due to a non-cash impairment charge ($33.8 million), an increase in operating expenses ($7.6 million), an increase in interest
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expense ($3.1 million) and an increase in depreciation expense ($2.9 million). The impairment charge wrote down the carrying value of certain assets associated with Supply Corporation and Empire’s Northern Access project. Additional details related to the Northern Access project are discussed in the Other Matters section below. The increase in operating expenses was primarily due to higher personnel costs, an increase in outside services expenses (including compressor and other pipeline maintenance costs), as well as higher power costs related to Empire’s electric motor drive compressor station. This increase in electric power costs is offset by an equal increase in revenue. The increase in interest expense is mainly due to an increase in intercompany short-term borrowings along with a higher weighted average interest rate on intercompany long-term borrowings. The increase in depreciation expense was primarily due to higher average depreciable plant in service compared to the prior year, partially offset by a reduction in certain Supply Corporation depreciation rates associated with its rate case settlement. The factors that decreased earnings were partially offset by the impact of higher operating revenues ($26.2 million), as discussed above, combined with an increase in other income ($1.6 million). The increase in other income is primarily due to an increase in interest income related to a higher weighted average interest rate on intercompany short-term notes receivables and a higher average amount outstanding on those receivables.
GATHERING
Revenues
Gathering Operating Revenues
| Year Ended September 30 | |||||||||||
| 2024 | 2023 | ||||||||||
| (Thousands) | |||||||||||
| Gathering | $ | 244,225 | $ | 230,317 | |||||||
Gathering Volume — (MMcf)
| Year Ended September 30 | |||||||||||
| 2024 | 2023 | ||||||||||
| Gathered Volume | 480,688 | 453,338 | |||||||||
2024 Compared with 2023
Operating revenues for the Gathering segment increased $13.9 million in 2024 as compared with 2023, which was driven primarily by a 27.4 Bcf increase in gathered volume. Gathered volume increased 47.7 Bcf in the Gathering segment’s eastern development areas (Trout Run and Tioga), partially offset by a 20.3 Bcf decrease in gathered volume in the Gathering segment’s western development area (Clermont). 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.
Earnings
2024 Compared with 2023
The Gathering segment’s earnings in 2024 were $106.9 million, an increase of $7.2 million when compared with earnings of $99.7 million in 2023. The increase in earnings was mainly due to higher gathering revenues ($11.0 million) driven by the increase in gathered volume, as discussed above, and lower interest expense ($0.6 million). The decrease in interest expense was primarily due to higher capitalized interest. This increase was partially offset by higher depreciation expense ($2.4 million) and higher operating expenses ($1.3 million). The increase in depreciation expense was largely due to additional plant in-service associated with the Tioga and Clermont gathering systems. The increase in operating expenses was largely attributable to higher material costs driven by new plant in-service and higher throughput, in addition to higher labor-related costs.
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UTILITY
Revenues
Utility Operating Revenues
| Year Ended September 30 | |||||||||||
| 2024 | 2023 | ||||||||||
| (Thousands) | |||||||||||