EDGAR 10-K Filing

Company CIK: 1069533
Filing Year: 2025
Filename: 1069533_10-K_2025_0001437749-25-036827.json

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ITEM 1. BUSINESS
Item 1. Business.
General and Historical Development
Resources was incorporated in the Commonwealth of Virginia on July 31, 1998 and, effective July 1, 1999, its subsidiaries were reorganized into the Resources holding company structure. Resources is currently composed of the following subsidiaries: Roanoke Gas and Midstream.
Roanoke Gas, originally established in 1883, was organized as a public service corporation under the laws of the Commonwealth of Virginia in 1912. The principal service of Roanoke Gas is the distribution and sale of natural gas to residential, commercial and industrial customers within its service territory in Roanoke, Virginia and the surrounding localities. Roanoke Gas also provides certain non-regulated services which account for less than 1% of consolidated revenues.
In July 2015, the Company formed Midstream for the purpose of becoming an investor in Mountain Valley Pipeline, LLC. The LLC was created to construct and operate interstate natural gas pipelines. Additional information regarding this investment is provided under Note 5 of the Company's annual consolidated financial statements and under the Equity Investment in Mountain Valley Pipeline section of Item 7.
Services
Roanoke Gas maintains an integrated natural gas distribution system to deliver natural gas purchased from suppliers to residential, commercial and industrial users in its service territory. The schedule below is a summary of customers, delivered volumes (expressed in DTHs), revenues and margin as a percentage of the total for each category. For the purposes of this schedule, margin is defined as revenues less cost of gas.
Customers
Volume
Revenue
Margin
Residential
91.3 %
31.3 %
58.0 %
62.2 %
Commercial
8.6 %
27.9 %
35.0 %
26.3 %
Industrial
0.1 %
40.8 %
6.2 %
10.0 %
Other
0.0 %
0.0 %
0.8 %
1.5 %
Total percent
100.0 %
100.0 %
100.0 %
100.0 %
Total value
62,527
11,493,415
$ 95,231,943
$ 52,680,989
Customers
Volume
Revenue
Margin
Residential
91.3 %
32.7 %
58.5 %
63.1 %
Commercial
8.6 %
29.5 %
34.0 %
25.3 %
Industrial
0.1 %
37.8 %
6.4 %
9.8 %
Other
0.0 %
0.0 %
1.1 %
1.8 %
Total percent
100.0 %
100.0 %
100.0 %
100.0 %
Total value
62,510
10,048,770
$ 84,533,101
$ 48,565,114
Roanoke Gas’ regulated natural gas distribution business accounted for more than 99% of Resources total revenues for fiscal years ended September 30, 2025 and 2024. The tables above indicate that residential customers represent over 91% of the Company’s customer total; however, they represent less than 35% of the total gas volumes delivered and more than half of the Company’s consolidated revenues and margin. Industrial customers primarily include transportation customers that purchase their natural gas directly from a supplier other than the Company and utilize Roanoke Gas’ natural gas distribution system for delivery to their operations. Most of the revenue billed for these customers, which is less than 10% of total revenues, relates only to transportation service, and not to the purchase of natural gas. Transportation customers account for more than 35% of total natural gas volume deliveries and approximately 10% of margin for the years presented.
The Company’s revenues are affected by changes in gas costs, changes in consumption volume due to weather and economic conditions and changes in the non-gas portion of customer billing rates. Increases or decreases in the cost of natural gas are passed on to customers through the PGA mechanism as explained in Note 1 of the consolidated financial statements.
The Company’s residential and commercial sales are primarily seasonal and subject to temperature sensitivity as the majority of the gas sold by Roanoke Gas to these customers is used for heating. For the fiscal year ended September 30, 2025, approximately 63% of the Company’s total DTH of natural gas deliveries and 76% of the residential and commercial deliveries were made in the five-month period of November through March.
Roanoke Gas relies on multiple interstate pipelines and gas storage, including those operated by Columbia Gas Transmission Corporation, LLC and Columbia Gulf Transmission Corporation, LLC (together “Columbia”), East Tennessee Natural Gas, LLC (“East Tennessee”), Tennessee Gas Pipeline, Midwestern Gas Transmission Company, Saltville Gas Storage Company, LLC ("Saltville") and Mountain Valley Pipeline, LLC ("Mountain Valley"), to transport natural gas from production and storage fields to Roanoke Gas’ distribution system. Roanoke Gas is directly served by Columbia, East Tennessee and Mountain Valley. Columbia historically has delivered more than 65% of the Company’s required gas supply, with East Tennessee and Mountain Valley delivering the remainder. The rates paid for interstate natural gas transportation and storage services are established by tariffs approved by FERC. The current pipeline and storage contracts expire at various times from calendar 2027 to 2044. The Company anticipates being able to renew these contracts or enter into other contracts to meet customers’ existing demand for natural gas.
The Company manages its pipeline contracts and LNG facility in order to provide for sufficient capacity to meet the current natural gas demands of its customers. The maximum daily winter capacity available for delivery into Roanoke Gas’ distribution system from the current interstate pipelines is 93,606 DTH per day. The LNG facility is capable of storing up to 200,000 DTH of natural gas in a liquid state for use during peak demand. Combined, the pipelines and LNG facility may provide up to 118,606 DTH on a single winter day.
The Company currently contracts with an asset manager to manage its pipeline transportation, storage rights, gas supply inventories and deliveries and serve as the primary supplier of natural gas for Roanoke Gas. Natural gas purchased under the asset management agreement is priced at indexed-based market prices as reported in major industry pricing publications. The current asset management agreement expires March 31, 2028.
The Company uses summer storage programs to supplement heating season gas supply requirements. The Company has contracted for 2.4 million DTH of storage capacity from Columbia, Tennessee Gas Pipeline and Saltville in addition to the capacity available at the Company's LNG facility. The balance of the Company’s annual natural gas requirements are met primarily through market purchases made by its asset manager.
In March 2023, Roanoke Gas began operation of its RNG facility. Total volume produced from RNG is less than 1% of current system demand.
Competition
The Company’s natural gas utility operates in a regulated, monopolistic environment. Roanoke Gas currently holds the only franchises and/or CPCNs to distribute natural gas in its Virginia service areas. These franchises generally extend for multi-year periods and are renewable by the municipalities, including exclusive franchises in the cities of Roanoke and Salem and the Town of Vinton, Virginia. All three franchises are set to expire December 31, 2035. The SCC issued an order granting a CPCN to furnish gas to all of Franklin County, Virginia. Roanoke Gas is serving the Franklin County area with natural gas delivered through the MVP.
Management anticipates that the Company will be able to renew all of its franchises prior to their current expiration date; however, there can be no assurance that a given jurisdiction will not refuse to renew a franchise or will not, in connection with the renewal of a franchise, attempt to impose restrictions or conditions that could adversely affect the Company’s business operations or financial condition. CPCNs, issued by the SCC, are generally of perpetual duration and subject to compliance with regulatory standards.
Although Roanoke Gas has exclusive rights for the distribution of natural gas in its service area, the Company competes with suppliers of other forms of energy such as fuel oil, electricity, propane and coal. Competition can be intense among the other energy sources with price being the primary consideration. This is particularly true for those industrial applications that have the ability to switch to alternative fuels. The relationship between supply and demand has the greatest impact on the price of natural gas. Greater demand for natural gas for electric generation and other uses can exert upward pressure on the price of natural gas.
Competition from renewable energy sources for generating electricity, such as solar and wind, is likely to increase as certain laws currently favor these energy sources or place restrictions on emissions from the burning of fossil fuels. However, the demand for all forms of energy, including natural gas, is being driven by consumers using more digital platforms and expanding their use of artificial intelligence. Growth in residential and commercial service has been steady as the Company continues to expand its customer base through a combination of extending distribution service and converting other energy users to natural gas.
Regulation
In addition to the regulatory requirements generally applicable to all companies, Roanoke Gas is also subject to additional regulation from federal, state and local authorities. At the federal level, the Company is subject to pipeline safety regulations issued by the Department of Transportation's Pipeline and Hazardous Materials Safety Administration.
At the state level, the SCC performs regulatory oversight including the approval of rates and other charges for natural gas sold to customers, the approval of agreements between or among affiliated companies involving the provision of goods and services, pipeline safety and certain other corporate activities of the Company, including mergers and acquisitions related to utility operations.
At the local level, Roanoke Gas is further regulated by the municipalities and localities that grant franchises for the placement of gas distribution pipelines and the operation of gas distribution networks within their jurisdictions.
Human Capital Resources
At September 30, 2025, Resources had 106 full-time employees. The Company’s business strategy and ability to serve customers relies on employing talented professionals and attracting, training, developing and retaining a skilled workforce. This is particularly relevant as the Company continues to project retirements of key personnel over the next several years. As the Company's workforce transforms, including departures and retirements, the Company has been successful in engaging the necessary qualified personnel to fill vacancies by reviewing and adjusting its compensation package to remain competitive in the current market environment.
Website Access to Reports
The Company’s website address is www.rgcresources.com. Information appearing on this website is not incorporated by reference in and is not a part of this annual report. The Company files reports with the SEC. A copy of this annual report, as well as other recent annual and quarterly reports, are available on the Company's website or through the SEC. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding the Company’s filings at www.sec.gov.

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ITEM 1A. RISK FACTORS
Item 1A. Risk Factors
Please carefully consider the risks described below regarding the Company. These risks are not the only ones faced by the Company. Additional risks not presently known to the Company or that the Company currently believes are immaterial may also impair business operations and financial results. If any of the following risks actually occur, the Company’s business, financial condition or results of operations could be adversely affected. In such case, the trading price of the Company’s common stock could decline and investors could lose all or part of their investment. The risk factors below are categorized by operational, regulatory and financial:
OPERATIONAL RISKS
Risks associated with the operation of a natural gas distribution pipeline and LNG storage facility.
Numerous potential risks are inherent in the operation of a natural gas distribution system and LNG storage facility, including unanticipated or unforeseen events that are beyond the control of the Company. Examples of such events include adverse weather conditions, acts of terrorism or sabotage, accidents and damage caused by third parties, equipment failure, failure of upstream pipelines and storage facilities, as well as catastrophic events such as explosions, fires, earthquakes, floods, or other similar events. These risks could result in injury or loss of life, property damage, pollution and customer service disruption resulting in potentially significant financial losses. The Company maintains insurance coverage to protect against many of these risks. However, if losses result from an event that is not fully covered by insurance, the Company’s financial condition could be significantly impacted if it were unable to recover such losses from customers through the regulatory rate-making process. Even if the Company did not incur a direct financial loss as a result of any of the events noted above, it could encounter significant reputational damage from a reliability, safety, integrity or similar viewpoint, potentially resulting in a longer-term negative earnings impact or decline in share price.
Security incident or cyber attacks on the Company’s computer or information technology systems.
The Company’s business operations and information technology systems are targets of cyber attack, and they may be vulnerable to an attack by individuals or organizations intending to disrupt the operations of the Company. Such an attack or cybersecurity incident on the Company’s information technology systems could result in corruption of the Company’s financial information; disruption of services to our customers; the unauthorized release of confidential customer, employee or vendor information; the interruption of natural gas deliveries to our customers; and/or compromise the safety of our distribution, transmission and storage systems. The Company has implemented policies, procedures and controls to prevent and detect these activities; however, there are no guarantees that Company processes will adequately protect against unauthorized access. In the event of an attack, the Company could be exposed to material financial and reputational risks, possible disruptions in natural gas deliveries or a compromise of the safety of the natural gas distribution system, as well as be exposed to claims by persons harmed by such an attack, all of which could materially increase the Company's costs to protect against such risks. The Company maintains cyber-insurance coverage, which does not protect the Company from cyber incidents but does provide some potential mitigation of the financial impacts resulting from such attacks. See Item 1C of this Form 10-K for additional discussion.
Volatility in the price and availability of natural gas.
Natural gas purchases represent the single largest expense of the Company. Increasing demand from other areas, including electricity generation, combined with other factors, have placed upward pressure on natural gas commodity prices in the past. If these factors return and continue for an extended period of time, higher natural gas prices could result in declining usage as well as increases in bad debt expense and increased competition from other energy providers.
Inability to attract and retain professional and technical employees.
The ability to implement the Company’s business strategy and serve customers is dependent upon employing talented professionals and attracting, training, developing and retaining a skilled workforce. As the Company expects key personnel to retire over the next several years, as well as higher mobility trends, failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and skills to new employees, or future availability and cost of contracted labor may adversely affect the ability to manage and operate the Company. In addition, certain specialized knowledge is required of the Company’s technical employees for construction and operation of the natural gas distribution facilities. If the Company is unable to attract and/or retain qualified employees, the Company could experience increased operating costs and expose the Company to other operational, reputational and financial risks.
Availability of sufficient and reliable pipeline capacity.
The Company is currently served directly by three interstate pipelines. These pipelines carry 100% of the natural gas transported to the Company’s distribution system. Depending on weather conditions and the level of customer demand, failure of one or more of these interstate transmission pipelines could have a major impact on the Company’s ability to meet customer demand for natural gas and adversely affect the Company’s earnings as a result of lost revenue and the cost of service restoration. Frequent or prolonged failure could lead customers to switch to alternative energy sources. Hurricanes, floods, fires and other natural or man-made disasters could damage or inhibit production and/or pipeline transportation facilities, which could result in decreased natural gas supplies. Capacity limitations on existing pipeline and storage infrastructure could impact the Company’s ability to obtain additional natural gas supplies, thereby limiting its ability to add new customers or meet increased customer demand thereby limiting future earnings potential.
Inability to complete necessary or desirable pipeline expansion or infrastructure improvement projects.
In order to serve new customers or expand service to existing customers, the Company installs new pipeline facilities and maintains, expands or upgrades its existing distribution, transmission and/or storage infrastructure. Various factors may prevent or delay the completion of such projects or make them more costly, such as the inability to obtain required approval from local, state and/or federal regulatory and governmental bodies, public opposition to the projects, inability to obtain adequate financing, competition for labor and materials, construction delays, cost overruns, and an inability to negotiate acceptable agreements relating to rights-of-way, construction or other material development components. As a result, the Company may not be able to adequately serve existing customers or expand its distribution system to support customer growth. These factors could negatively impact earnings.
Increased dependence on technology may hinder the Company’s business operations and adversely affect its financial condition and results of operations if such technologies fail.
Over the last several years, the Company has implemented or acquired a variety of technological tools including both Company-owned information technology and technological services provided by outside parties. Additionally, the Company upgraded its financial system and is in the process of updating its customer information system. These tools and systems support critical functions including, scheduling and dispatching of service technicians, automated meter reading systems, customer care and billing, revenue recognition, operational plant logistics, and external financial reporting. Issues in the implementation or the failure of these or other similarly important technologies, or the Company’s inability to have these technologies supported, updated, expanded, or integrated into other technologies, could hinder its business operations and adversely impact its financial condition and results of operations. Although the Company has, when possible, developed alternative sources of technology and built redundancy into its computer networks and tools, there can be no assurance that these efforts would protect against all potential issues related to the loss of any such technologies.
Geographic concentration of business activities.
The Company's business activities are concentrated in the Roanoke Valley and surrounding areas. Changes in the local economy, politics, regulations and weather patterns or other factors limiting demand for natural gas could negatively impact the Company's existing customer base, leading to declining usage patterns and financial condition of customers. Furthermore, these changes could also limit the Company's ability to serve its customers or add new customers within its service territory. These factors could adversely affect earnings.
Competition from other energy providers.
The Company competes with other energy providers in its service territory, including those that provide electricity, propane, coal, fuel oil, wind and solar. Price is a significant competitive factor. Higher natural gas costs or decreases in the price of other energy sources may enhance competition and encourage customers to switch to alternative energy sources, thus lowering natural gas deliveries and earnings. Price considerations could also inhibit customer and revenue growth if builders and developers do not perceive, or are regulatorily prevented from installing, natural gas as a better value than other energy options and elect to install heating systems that use energy sources, including those perceived as more environmentally friendly.
REGULATORY RISKS
Laws or regulations associated with ESG matters.
Focus on ESG matters related to, among other things, concerns raised by advocacy groups about climate change, social issues and corporate governance may lead to increased regulatory review, which in turn may lead to new state and federal safety laws, regulations, guidelines, and enforcement interpretations. Social, corporate and environmental governance initiatives retain importance. In addition, several federal and state legislative and regulatory initiatives have been proposed and enacted in recent years in an attempt to limit the effects of climate change, including greenhouse gas emissions such as those created by the combustion of fossil fuels, including natural gas. Full implementation and/or passage of environmental legislation or implementation of regulations that mandate the use of electric rather than gas appliances, or reductions in greenhouse gas emissions or other similar restrictions could have a negative effect on the Company’s core operations and its investment in the LLC. Such legislation could impose limitations on greenhouse gas emissions, require funding of new energy efficiency objectives, impose new operational requirements or lead to other additional costs to the Company. Regulations restricting or prohibiting the use of coal as a fuel for electric power generation has increased the demand for natural gas, and could at some point potentially result in natural gas supply concerns and higher costs for natural gas. Legislation or regulations could limit the exploration and development of natural gas reserves, making the price of natural gas less competitive and less attractive as a fuel source for consumers. Future legislation could also place limitations on the amount of natural gas used by businesses and homeowners to reduce the level of greenhouse gas emissions, resulting in reduced deliveries and earnings or provide incentives to customers to utilize alternative energy sources not associated with fossil fuels.
In addition, advocacy groups, both domestically and internationally, have campaigned for governmental and private action to influence change in the business strategies of oil and gas companies, including through the investment and voting practices of investment advisors, public pension funds, universities and other members of the investing community. These activities include increasing attention and demands for action related to climate change and energy transition matters, such as promoting the use of substitutes to fossil fuel and encouraging the divestment of investments in the oil and gas industry, as well as pressuring lenders and other financial services companies to limit or curtail activities with oil and gas companies. If investors or financial institutions shift funding away from companies in the oil and gas industry, the Company’s access to and costs of capital or the market for the Company’s securities may be adversely impacted.
Regulatory actions or failure to obtain timely rate relief.
The Company’s natural gas distribution operations are regulated by the SCC. The SCC approves the rates that the Company charges its customers. During periods of enhanced inflationary pressure or the incurrence of significant additional costs, if the SCC did not timely authorize rates that provide for the recovery of such costs including a reasonable rate of return on investment in natural gas distribution facilities, earnings could be negatively impacted.
Furthermore, issuance of debt and equity by Roanoke Gas is also subject to SCC regulation and approval. Delays or lack of approvals could inhibit the ability to access capital markets and negatively impact liquidity or earnings.
Increased compliance and pipeline safety requirements and fines.
The Company is committed to the safe and reliable delivery of natural gas to its customers. Working in concert with this commitment are numerous federal and state laws and regulations. Failure to comply with these laws and regulations could result in the levy of significant fines. There are inherent risks that may be beyond the Company’s control, including third-party actions, which could result in damage to pipeline facilities, injury and even death. Such incidents could subject the Company to lawsuits, large fines, increased scrutiny and loss of customers, all of which could have a significant effect on the Company’s financial position and results of operations.
FINANCIAL RISKS
Access to capital to maintain liquidity.
The Company relies on a variety of capital sources to operate its business and fund capital expenditures, including internally generated cash from operations, borrowings under its line-of-credit, proceeds from the issuance of additional shares of its common stock and other sources. Access to a line-of-credit is essential to provide seasonal funding of natural gas operations and provide capital budget bridge financing. Access to capital markets and other long-term funding sources is important for refinancing and capital outlays. The ability of the Company to secure longer-term financing and to maintain and renew its line-of-credit is critical to operations. Adverse market trends, market disruptions or deterioration in the financial condition of the Company could increase the cost of borrowing, restrict the Company's ability to issue additional shares of its common stock or otherwise limit the Company’s ability to secure adequate funding.
Failure to comply with debt covenant requirements.
The Company's long-term debt obligations and bank line-of-credit contain financial covenants. Noncompliance with any of these covenants could result in an event of default which, if not cured or waived, could accelerate payment on outstanding debt obligations or cause prepayment penalties. In such an event, the Company may not be able to refinance or repay all of its indebtedness, pay dividends or have sufficient liquidity to meet operating and capital expenditure requirements. Any such acceleration would cause a material adverse change in the Company's financial condition.
Investment in Mountain Valley Pipeline, LLC.
The MVP went into service in June 2024. The LLC’s gas infrastructure facilities are subject to many operational risks. Operational risks could result in, among other things, lost revenues due to prolonged outages, increased expenses due to monetary penalties or fines for compliance failures, liability to third parties for property damage and personal injury, a failure to perform under applicable sales agreements and associated loss of revenues from terminated agreements or liability for liquidated damages under continuing agreements. The consequences of these risks, if realized, could adversely affect the LLC’s business, cash flows, financial condition, results of operations and prospects. Uncertainties and risks inherent in operating and maintaining the LLC's facilities include, but are not limited to, risks associated with the success of new projects to generate additional cash flows. The LLC’s business, cash flows, financial condition, results of operations and prospects potentially could be adversely affected by weather conditions, including, but not limited to, the impact of severe weather. Threats of terrorism and catastrophic events resulting from terrorism, sabotage, cyber-attacks, or individuals and/or groups attempting to disrupt the LLC’s business, or the businesses of third parties, may materially adversely affect the LLC’s business, financial condition, results of operations and prospects.
Any adverse developments, such as those noted above, could have a significant effect on the LLC and the Company's earnings, cash flows and financial position, and materially impact Resources' consolidated financial position and results of operations, including Resources' ability to pay shareholder dividends at the current level or remain in compliance with credit agreement covenants.
Obligations for income taxes that may arise from examinations by taxing authorities.
The Company is subject to federal and state income taxes as prescribed by the laws within the United States. Significant judgments are required in determining the provisions for income taxes. Our total income tax expense could be affected by changes in tax rates in various jurisdictions, changes in the valuation of deferred tax assets and liabilities or changes in tax laws or their interpretation. In preparing its tax provisions and returns, the Company must make calculations and assumptions regarding tax treatment of various transactions, including the applicability of tax credits. The Company’s tax returns are subject to examination by the IRS and state tax authorities as disclosed in Note 9 of the consolidated financial statements. Although the Company utilizes the assistance of tax professionals in the preparation of its tax returns, the final determination of tax examinations and any related litigation could be materially different than what is reflected in historical income tax provisions and accruals. If a taxing authority disagrees with the positions we have taken, the Company could face additional tax liability, including interest and penalties, which could adversely affect our financial results.
The cost of providing post-retirement benefits.
The Company provides certain pension and post-retirement benefits. The costs of providing defined benefit pension and retiree medical plans are dependent on a number of factors such as the rates of return on plan assets, discount rates used in determining plan liabilities, the level of interest rates used to measure the required minimum funding levels of the plan, future government regulation, changes in life expectancy and required or voluntary contributions made to the plan. Changes in actuarial assumptions and differences between the assumptions and actual results, as well as a significant decline in the value of investments that fund these plans, if not offset or mitigated by a decline in plan liabilities, could increase the expense of these plans and require significant additional funding. Although the Company has soft-frozen both plans to limit future growth in each plan's liabilities, ongoing funding obligations and expenses could have a material impact on the Company's financial position, results of operation and cash flows should there be a material reduction in the amount of the recovery of these costs through rates currently charged to customers or significant delays in the timing of the recovery of such costs.
Exposure to market risks.
The Company is subject to market risks that are beyond the Company’s control, such as commodity price volatility and interest rate risk. The Company is generally isolated from commodity price risk through the PGA mechanism. With respect to interest rate risk, there has been significant movement in interest rates in recent years. Much of the Company's outstanding debt is comprised of fixed rate notes or have interest rate swaps in place. However, higher interest rates do impact the Company through higher borrowing costs on Roanoke Gas' line-of-credit and Midstream's variable rate credit facilities as well as any future borrowings by the Company.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments.
None.

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ITEM 2. PROPERTIES
Item 2. Properties.
Included in “Utility Property” on the Company’s consolidated balance sheet are storage plant, transmission plant, distribution plant and general plant of Roanoke Gas consistent with other natural gas utilities. The Company has approximately 1,184 miles of transmission and distribution pipeline representing 89% of the total utility property. The transmission and distribution pipelines are located on or under public roads, highways or private property for which the Company has obtained the legal authorization and rights to operate.
Roanoke Gas currently owns and operates eleven metering stations through which it measures and regulates the gas being delivered by its suppliers. These stations are located at various points throughout the Company’s distribution system.
Roanoke Gas owns a liquefied natural gas storage facility located in its service territory that has the capacity to store up to 200,000 DTH of natural gas.
Roanoke Gas also began operation of an RNG facility, that it owns, during fiscal 2023 as part of a cooperative agreement with the local water authority to produce commercial quality biogas at the regional pollution control facility. The Company leases the land upon which the RNG facility is located.
The Company’s executive, accounting and business offices, along with its operations departments, are located on Kimball Avenue in Roanoke, Virginia.
Although the Company considers its present properties to be adequate, management continues to evaluate the adequacy of its current facilities as additional needs arise.

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceedings.
The Company is not known to be a party to any pending legal proceedings.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures.
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Market Information
Resources' common stock is listed on the Nasdaq Global Market under the trading symbol RGCO. Payment of dividends is within the discretion of the Board of Directors and depends on, among other factors, earnings, capital requirements, and the operating and financial condition of the Company.
Range of Bid Prices
Cash Dividends
Year Ending September 30, 2025
High
Low
Declared
First Quarter
$ 23.49
$ 19.62
$ 0.2075
Second Quarter
21.52
19.37
0.2075
Third Quarter
23.28
20.27
0.2075
Fourth Quarter
23.09
19.68
0.2075
Year Ending September 30, 2024
First Quarter
$ 21.69
$ 15.42
$ 0.2000
Second Quarter
21.34
18.08
0.2000
Third Quarter
21.51
18.90
0.2000
Fourth Quarter
22.92
19.20
0.2000
As of November 28, 2025, there were 884 holders of record of the Company’s common stock. This number does not include all beneficial owners of common stock who hold their shares in “street name."
A summary of the Company’s equity compensation plans follows as of September 30, 2025:
(a)
(b)
(c)
Plan category
Number of securities to be issued upon exercise of outstanding options, warrants and rights
Weighted-average exercise price of outstanding options, warrants and rights
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders
28,000
$ 18.98
437,348
Equity compensation plans not approved by security holders
-
-
-
Total
28,000
$ 18.98
437,348

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. [Reserved].

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Overview
Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 62,500 residential, commercial and industrial customers in Roanoke, Virginia, and the surrounding localities, through its Roanoke Gas subsidiary. Midstream, a wholly owned subsidiary of Resources, is a less than 1% investor in the MVP, Southgate and Boost. More information regarding the investment in MVP is provided below and under the Equity Investment in Mountain Valley Pipeline section.
The utility operations of Roanoke Gas are regulated by the SCC, which oversees the terms, conditions and rates charged to customers for natural gas service, safety standards, extension of service and depreciation. Nearly all of the Company’s revenues are derived from the sale and delivery of natural gas to Roanoke Gas customers based on rates and fees authorized by the SCC. These rates are designed to provide the Company with the opportunity to recover its gas and non-gas expenses and to earn a reasonable rate of return for shareholders based on normal weather. These rates are determined based on various rate applications filed with the SCC. Generally, investments related to extending service to new customers are recovered through the additional revenues generated by the non-gas base rates in place at that time. The investment in replacing and upgrading existing infrastructure, as well as recovering increases in non-gas expenses due to inflationary pressures, regulatory requirements or operation needs, are generally not recoverable until a formal rate application is filed to include additional investment and higher costs, and new non-gas base rates are approved.
The Company is also subject to regulation from the Department of Transportation in regard to the construction, operation, maintenance, safety and integrity of its transmission and distribution pipelines, as well as the FERC, which regulates the prices for the transportation and delivery of natural gas to the Company's distribution system and underground storage services. In addition, Roanoke Gas is subject to other regulations which are not necessarily industry specific.
On February 2, 2024, primarily in response to continued inflationary pressures, Roanoke Gas filed for a non-gas base rate increase of $4.33 million. The filing also reflected an increase in the Company's authorized return on equity from 9.44% to 10.35%. The new interim non-gas base rates went into effect for customer billings on or after July 1, 2024, subject to refund. On October 16, 2024, the Company reached a settlement with the SCC staff on all outstanding issues in the case. Under the terms of the settlement, the Company agreed to an annual incremental revenue requirement increase of $4.08 million based on a return on equity of 9.90%. On April 10, 2025, the SCC issued a final order approving the settlement in its entirety. The order also directed Roanoke Gas to refund the excess revenues collected during the time the interim rates were in effect with interest. The refunds to customers, which had previously been accrued as a regulatory liability, were made to customers in May 2025.
As the Company’s business is seasonal in nature, volatility in winter weather and the commodity price of natural gas can impact the effectiveness of the Company’s rates in recovering its costs and providing a reasonable return for its shareholders. In order to mitigate the effect of weather variations and other factors not provided for in the Company's base rates, Roanoke Gas has certain approved rate mechanisms in place that help provide stability to customer bills and earnings, adjust for volatility in the price of natural gas and provide a return on qualified infrastructure investment. These mechanisms include the SAVE Rider, WNA, ICC, RNG Rider and PGA.
The SAVE Plan and Rider provides the Company with a mechanism through which it recovers costs related to SAVE qualified infrastructure investments on a prospective basis, until such time a formal rate application is filed incorporating these investments in non-gas base rates. Roanoke Gas filed and received approval from the SCC for an updated annual SAVE Rider rate which became effective October 1, 2024. As a result of the updated SAVE Rider, SAVE Plan revenues increased to approximately $1,588,000 in fiscal 2025 from approximately $461,000 in fiscal 2024. Roanoke Gas filed and received approval from the SCC for an updated annual SAVE Rider rate to become effective October 1, 2025 that will result in approximately $2,610,000 of SAVE-related revenues during fiscal 2026. See Note 4 of the consolidated financial statements for additional information regarding the SAVE Plan and Rider.
The WNA mechanism reduces the volatility in earnings due to the variability in temperatures during the heating season. The WNA is based on the most recent 30-year temperature average and provides the Company with a level of earnings protection when weather is warmer than normal and provides its customers with a level of price protection when the weather is colder than normal. The WNA allows the Company to recover from customers the lost margin, excluding gas costs, from the impact of warmer-than-normal weather and correspondingly requires the Company to refund to customers the excess margin earned for colder-than-normal weather. The WNA mechanism used by the Company is based on a linear regression model that determines the value of a single heating degree day and thereby estimates the revenue adjustment based on weather variance from normal. Any billings or refunds related to the WNA are completed following each WNA year, which extends for the 12-month period from April to March. The Company recorded approximately $1,056,000 and $3,761,000 in additional revenues under the WNA for weather that was approximately 4% and 20% warmer than normal for the fiscal years ended September 30, 2025 and 2024, respectively. The number of heating degree days used to determine normal can change annually as a new year is added to the 30-year period and the oldest year is removed. As a result of adding warmer than normal years to replace colder years, the number of heating degree days that defines normal has trended downward over the last several years.
The Company also has an approved rate structure that mitigates the impact of financing costs of its natural gas inventory. Under this rate structure, Roanoke Gas recognizes revenue by applying the ICC factor, based on the Company’s weighted-average cost of capital, including interest rates on short-term and long-term debt, and the Company’s authorized return on equity, to the average cost of natural gas inventory during the period. Total ICC revenues decreased from approximately $728,000 in fiscal 2024 to $587,000 in fiscal 2025 due to lower natural gas commodity prices during the 2024 summer storage injection season resulting in a lower average cost of natural gas in storage. The average price of gas in storage during fiscal 2025 declined by 12% compared to fiscal 2024, while the average price of gas in storage at September 30, 2025 increased by 5% compared to the same period last year. If natural gas prices remain at or higher than the prior year, the average dollar balance of gas in storage may increase based on current storage levels and due to an increased ICC factor from the prior year may lead to higher ICC revenues in fiscal 2026.
In March 2023, Roanoke Gas began the operation of the RNG facility to produce commercial quality biogas for delivery into its distribution system through a cooperative agreement with the Western Virginia Water Authority. With SCC approval, Roanoke Gas is allowed to recover the costs associated with the investment in RNG facilities and related operating costs through an RNG Rider added to customer bills. The customer benefits from this program through the monetization of environmental credits generated through RNG production, which are returned to customers through the RNG Rider. Total RNG revenue increased from approximately $1,629,000 in fiscal 2024 to $1,760,000 in fiscal 2025. See Note 4 of the consolidated financial statements for more information on RNG.
The cost of natural gas is a pass-through cost and is independent of the Company's non-gas rates. Accordingly, the Company's approved billing rates include a component designed to allow for the recovery of the cost of natural gas used by its customers. This rate component, referred to as the PGA, allows the Company to pass along to its customers increases and decreases in natural gas costs through a quarterly filing (or more frequent if necessary) with the SCC. Once SCC approval is received, the Company adjusts the gas cost component of its rates. As actual costs and usage will differ from the projections used in establishing the PGA rate, the Company will either over-recover or under-recover its actual gas costs during the period. The difference between actual costs incurred and costs recovered through the application of the PGA is recorded as a regulatory asset or liability. At the end of the annual deferral period, the balance is amortized over an ensuing 12-month period as amounts are reflected in customer billings.
Inflation and Rising Prices
Natural gas commodity, delivery and storage capacity costs constitute the single largest expense of the Company, representing 55% of fiscal 2025 total operating expenses. After peaking in December 2022, natural gas commodity prices decreased significantly for the remainder of fiscal 2023 and through fiscal 2025. The decline in prices was primarily due to improved supply availability resulting from a warm winter season. Roanoke Gas recovers natural gas costs through the PGA mechanism as noted above; however, in times where commodity prices rapidly increase, the timing of recovery may lag. Increasing natural gas prices, especially in relation to other energy options, may lead to reductions in energy consumption through customer conservation or fuel switching. In addition, there is potential for higher bad debts related to customers' inability to pay higher natural gas bills.
The Company continues to experience inflation over the 2% level targeted by the Federal Reserve. Inflation levels in health care spending, certain types of insurance, contracted services and IT service costs, as well as other items, continue to put upward pressure on the Company's expenses. The Company recovers non-gas related costs through the non-gas portion of its tariff rates, which are adjusted through a non-gas base rate application. Unlike the rate adjustments for the gas portion of rates which are done administratively, the non-gas base rate application process can result in an inherent lag in non-gas expense recovery. Therefore, authorized non-gas base rates may not keep pace with rising costs during inflationary periods. Management regularly evaluates the Company's operations, economic conditions and other factors to assess the need to apply for a non-gas base rate adjustment. Accordingly, on December 2, 2025, the Company filed a non-gas base rate application with the SCC to increase revenues by $4.3 million annually.
Results of Operations
The analysis on the results of operations is based on the consolidated operations of the Company, which are primarily associated with the utility segment. Additional segment analysis is provided when Midstream's investment in affiliates represents a significant component of the comparison. Net income increased by $1,519,074 from the prior year primarily due to the implementation of higher non-gas base rates and record natural gas deliveries, as well as lower post-retirement benefit costs, partially offset by lower WNA revenues and lower equity earnings from the MVP as the project transitioned from construction into service.
The Company's operating revenues are affected by the cost of natural gas, as reflected in the consolidated statement of income under the line item cost of gas - utility. The cost of natural gas, which includes commodity price, transportation, storage, injection and withdrawal fees, with any increase or decrease offset by a correlating change in revenue through the PGA, is passed through to customers at cost. Accordingly, management believes that gross utility margin, a non-GAAP financial measure defined as utility revenues less cost of gas, is a useful and relevant measure to analyze financial performance. The term gross utility margin is not intended to represent or replace gross margin, the most comparable GAAP financial measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. A reconciliation between gross utility margin and gross margin is presented under the Gross Utility Margin section below.
The following results of operations analyses will reference gross utility margin.
Fiscal Year 2025 Compared with Fiscal Year 2024
The tables below reflect operating revenues, volume activity and heating degree days.
Operating Revenues
Year Ended September 30,
Increase / (Decrease)
Percentage
Gas utility
$ 95,231,943
$ 84,533,101
$ 10,698,842
%
Non utility
102,269
108,131
(5,862 )
(5 )%
Total operating revenues
$ 95,334,212
$ 84,641,232
$ 10,692,980
%
Delivered Volumes
Year Ended September 30,
Increase
Percentage
Regulated natural gas (DTH):
Residential and commercial
6,804,489
6,252,546
551,943
%
Transportation and interruptible
4,688,926
3,796,224
892,702
%
Total delivered volumes
11,493,415
10,048,770
1,444,645
%
HDD
3,655
3,094
%
Total gas utility operating revenues for the year ended September 30, 2025 increased by 13% from the year ended September 30, 2024 primarily due to the implementation of a non-gas base rate increase, along with higher delivered volumes, gas costs and SAVE revenues, partially offset by a decrease in WNA revenue. The non-gas base rate increase implemented in July 2024 was the main contributing factor to an approximate $5.6 million increase in non-gas volumetric revenues. In addition, total heating degree days increased by 18% from the prior fiscal year, resulting in a 9% increase in the weather-sensitive residential and commercial volumes, while transportation and interruptible volumes increased 24%, primarily driven by business activity of a single, multi-fuel customer during the period. Total gas costs also increased over the prior year primarily due to pipeline capacity charges increasing over $4.0 million as a result of higher rates and MVP capacity. SAVE Plan revenues increased as Roanoke Gas continues to invest in qualified SAVE infrastructure projects, resulting in approximately $1,127,000 more revenue compared to the same period in the prior year. WNA revenues declined approximately $2.7 million from the prior fiscal year as weather was only 4% warmer than normal during the current year compared to 20% warmer than normal during the prior year.
Gross Utility Margin
Year Ended September 30,
Increase
Percentage
Gas utility revenues
$ 95,231,943
$ 84,533,101
$ 10,698,842
%
Cost of gas - utility
42,550,954
35,967,987
6,582,967
%
Gross utility margin
$ 52,680,989
$ 48,565,114
$ 4,115,875
%
Gross utility margin increased over the prior fiscal year primarily as a result of the implementation of new non-gas base rates and increases in SAVE revenues, slightly offset by the reduction in ICC revenues. The volumetric margin, net of the WNA, increased by approximately $2.8 million primarily due to the new non-gas base rates and increases in transportation and interruptible volumes. As previously discussed, the SAVE Plan contributed an additional $1,127,000 to margin, while ICC revenues decreased by approximately $141,000 due to lower cost and volumes of gas in storage.
The changes in the components of the gross utility margin are summarized below:
Years Ended September 30,
Increase
(Decrease)
Customer base charge
$ 16,334,578
$ 16,235,406
$ 99,172
SAVE Plan
1,588,240
460,758
1,127,482
Volumetric
31,151,138
25,600,298
5,550,840
WNA
1,055,552
3,760,540
(2,704,988 )
ICC
586,759
727,825
(141,066 )
RNG
1,760,287
1,628,926
131,361
Other revenues
204,435
151,361
53,074
Total
$ 52,680,989
$ 48,565,114
$ 4,115,875
Reconciliation between gross utility margin and gross margin is presented below:
Gas Utility
Investment in Affiliates
Consolidated Total
For the Year Ended September 30, 2025:
Operating revenues
Gas utility
$ 95,231,943
$ -
$ 95,231,943
Non utility
102,269
-
102,269
Total operating revenues
95,334,212
-
95,334,212
Cost of sales
Cost of gas - utility
(42,550,954 )
-
(42,550,954 )
Cost of sales - non utility
(19,919 )
-
(19,919 )
Depreciation and amortization
(11,470,641 )
-
(11,470,641 )
Operations and maintenance
(19,729,415 )
(181,995 )
(19,911,410 )
Total cost of sales
(73,770,929 )
(181,995 )
(73,952,924 )
Gross margin (GAAP)
21,563,283
(181,995 )
21,381,288
Corporate and other, net
(82,350 )
-
(82,350 )
Depreciation and amortization
11,470,641
-
11,470,641
Operations and maintenance
19,729,415
181,995
19,911,410
Gross utility margin (Non-GAAP)
$ 52,680,989
$ -
$ 52,680,989
Gas Utility
Investment in Affiliates
Consolidated Total
For the Year Ended September 30, 2024:
Operating revenues
Gas utility
$ 84,533,101
$ -
$ 84,533,101
Non utility
108,131
-
108,131
Total operating revenues
84,641,232
-
84,641,232
Cost of sales
Cost of gas - utility
(35,967,987 )
-
(35,967,987 )
Cost of sales - non utility
(24,003 )
-
(24,003 )
Depreciation and amortization
(10,518,094 )
-
(10,518,094 )
Operations and maintenance
(18,215,354 )
(133,486 )
(18,348,840 )
Corporate and other
-
-
(5,896 )
Total operations and maintenance
(18,215,354 )
(133,486 )
(18,354,736 )
Total cost of sales
(64,725,438 )
(133,486 )
(64,864,820 )
Gross margin (GAAP)
19,915,794
(133,486 )
19,776,412
Corporate and other, net
(84,128 )
-
(78,232 )
Depreciation and amortization
10,518,094
-
10,518,094
Operations and maintenance
18,215,354
133,486
18,348,840
Gross utility margin (Non-GAAP)
$ 48,565,114
$ -
$ 48,565,114
Operations and Maintenance Expense - Operations and maintenance expense increased by $1,556,674, or 8%, over the prior year primarily due to inflationary effects on personnel costs and contracted services, RNG-related costs and bad debt expense. Personnel costs and contracted services increased by approximately $969,000 due to increased staffing and the inflationary impact on salaries and benefits. RNG expenses increased approximately $231,000 primarily due to increases in electric and telemetering charges. Bad debt expense increased by approximately $170,000 due to higher bills from colder weather and more inactive accounts resulting from non-pay customer turnoffs. Increased corporate insurance premiums accounted for much of the remaining increase.
Taxes Other Than Income Taxes - Taxes other than income taxes increased by $239,135, or 9%, primarily due to higher property tax rates and growth in utility property, as well as increases in payroll taxes related to increased staffing and compensation.
Depreciation and Amortization - Depreciation and amortization expense increased by $952,547, or 9%, corresponding to a similar increase in net additions to depreciable utility property. Increases in fixed assets with shorter useful lives during the current fiscal year resulted in depreciation expense increasing slightly more than the 6% increase in utility property.
Equity in Earnings of Unconsolidated Affiliate - The equity in earnings of the MVP investment decreased by $617,239, or 16%. With the MVP in service, the Company now recognizes its share of operational earnings from the MVP, favorably adjusted for the amortization of a basis difference that arose when the Company recorded an other-than-temporary impairment of its investment in 2022. These in-service earnings did not fully replace the amount of AFUDC recognized while construction activities were ongoing during the first eight months of fiscal 2024. See Note 5 of the consolidated financial statements for additional information related to the MVP.
Other Income, Net - Other income increased by $1,204,122, primarily due to an approximate $1,129,000 decrease in postretirement benefit plan costs as a result of actuarial changes, coupled with an increase of approximately $237,000 in revenue sharing related to the asset management agreements, which are described in more detail in Note 14 of the consolidated financial statements.
Interest Expense - Total interest expense remained relatively flat over the prior year, increasing slightly by $38,626, or 1%, primarily due to higher borrowing levels. Total average debt outstanding during fiscal 2025 increased by 2% from fiscal 2024. Roanoke Gas' total average debt outstanding increased by approximately $1,346,000 associated with net borrowings under the Company's line-of-credit, while Midstream's total average debt outstanding increased by approximately $1,441,000 during the year. There were minimal fluctuations in the weighted-average interest rates between the periods. See Note 6 and 7 of the consolidated financial statements for more information on the Company's debt.
Income Taxes - Income tax expense increased by $394,924, or 11%, corresponding to an increase in pre-tax income. The effective tax rate was 23.6% and 23.9% for fiscal 2025 and 2024, respectively. The effective tax rate is below the combined statutory state and federal rate due to the amortization of excess deferred taxes and tax credits. See Note 9 of the consolidated financial statements for the impact of tax credits on the effective tax rate.
Earnings Per Share and Dividends - Basic and diluted earnings per share were $1.29 in fiscal 2025 compared to $1.16 per share in fiscal 2024. Dividends declared per share of common stock were $0.83 in fiscal 2025 compared to $0.80 in fiscal 2024.
Capital Resources and Liquidity
Due to the capital intensive nature of the utility business, as well as the impact of weather variability, the Company’s primary capital needs are the funding of its capital projects, the seasonal funding of its natural gas inventories and accounts receivables, debt service and payment of dividends to shareholders. The Company anticipates funding these items through its operating cash flows, credit availability under short-term and long-term debt agreements and proceeds from the sale of its common stock.
Cash and cash equivalents increased by approximately $1,426,000 in fiscal 2025 compared to a decrease of approximately $618,000 in fiscal 2024. The following table summarizes the categories of sources and uses of cash:
Cash Flow Summary
Years Ended September 30,
Net cash provided by operating activities
$ 28,948,149
$ 17,433,625
Net cash used in investing activities
(20,733,615 )
(22,033,632 )
Net cash provided by (used in) financing activities
(6,788,350 )
3,981,761
Net increase (decrease) in cash and cash equivalents
$ 1,426,184
$ (618,246 )
Cash Flows Provided by Operating Activities:
The seasonal nature of the natural gas distribution business causes operating cash flows to fluctuate significantly during the year, as well as from year to year. Factors, including weather, energy prices, natural gas storage levels and customer collections, all contribute to working capital levels and related cash flows. Generally, operating cash flows are positive during the second and third fiscal quarters as a combination of earnings, declining storage gas levels and collections on customer accounts all contribute to higher cash levels. During the first and fourth fiscal quarters, operating cash flows generally decrease due to the combination of increasing natural gas storage levels and rising customer receivable balances.
Cash flows from operating activities increased by $11.5 million from the prior year. The increase in operating cash flows is primarily due to net income increasing approximately $1,519,000, along with the cash distributions received from the LLC, direct impacts from weather and increased pipeline and storage capacity charges. During fiscal 2025, the Company received approximately $3,645,000 in quarterly cash distributions from the LLC, which has been accounted for as a return on its invested capital. The timing of collections related to gas costs, RNG and WNA resulted in approximately $5,011,000 in additional operating cash. Colder weather and increased gas costs compared to the prior year resulted in higher accounts receivable and accounts payable balances. Pipeline and storage capacity charges during fiscal 2025 increased over $3,400,000 from the prior year. Additionally, total commodity costs increased from $3.44 per DTH in fiscal 2024 to $3.64 per DTH in fiscal 2025.
Cash Flows Used in Investing Activities:
Investing activities primarily consist of expenditures related to Roanoke Gas' utility property, which includes replacing aging natural gas pipe with new plastic or coated steel pipe, improvements to the LNG plant and gas distribution system facilities and expansion of its natural gas system to meet the demands of customer growth. New customer demand for natural gas continues to be steady and therefore extending the natural gas distribution system within its service territory is also a priority. Roanoke Gas' expenditures were approximately $20.7 million and $22.1 million in fiscal 2025 and 2024, respectively. The $1.4 million decrease in expenditures is primarily due to higher prior-year investment for the MVP gate stations, which were placed into service in fiscal 2024. Roanoke Gas renewed 4.2 miles of main and 311 service lines and 5.4 miles of main and 412 service lines in fiscal years 2025 and 2024, respectively. Under the SCC approved SAVE Plan and Rider, the Company is continuing its focus on SAVE infrastructure replacement projects, including the replacement of pre-1973 first generation plastic pipe. Roanoke Gas’ capital expenditures included costs to extend natural gas distribution mains and services to 594 new customers in fiscal 2025, compared to 521 new customers in fiscal 2024.
Capital expenditures are expected to be approximately $22 million annually over the next few years as Roanoke Gas continues to focus on its SAVE Plan, as well as system improvements and customer growth. The Company expects to utilize its operating cash flows and credit facilities, as well as to consider additional long-term debt and equity capital, to meet the funding requirements of these planned expenditures.
Investing cash flows also reflects the fiscal 2025 funding of approximately $76,000 for Midstream's participation in the LLC, up from approximately $18,000 in fiscal 2024. Now that the MVP is in service, Midstream will be required to make periodic capital investment related to ongoing MVP operations requirements and system improvements. Midstream has and will continue to make capital investments in Southgate and Boost. The targeted timing for completion of the Southgate project is 2028 and the Boost project is 2029.
Cash Flows Provided by Financing Activities:
Financing activities generally consist of borrowings and repayments under credit agreements, issuance of common stock and the payment of dividends. Net cash flows used in financing activities were approximately $6.8 million in fiscal 2025, compared to $4.0 million in net cash flows provided by financing activities in fiscal 2024. The $10.8 million decrease in financing cash flows is primarily attributable to net borrowings of approximately $751,000 under Roanoke Gas' line-of-credit during fiscal 2025 compared to net borrowings of $6.8 million in the same period last year. In addition, during fiscal 2025, Resources issued a total of 88,409 shares of common stock, primarily from DRIP activity, resulting in net proceeds of approximately $1.8 million. No shares were issued through the ATM program during fiscal 2025. During fiscal 2024, the Company realized $4.7 million from the issuance of 234,645 shares through the ATM program and DRIP activity. Cash outflows for dividend payments were $8.5 million as the annualized dividend rate increased from $0.80 to $0.83 per share and total outstanding shares increased as a result of the stock issuance activity. The Company’s consolidated capitalization was 43.7% equity and 56.3% long-term debt at September 30, 2025, exclusive of unamortized debt expense. This compares to 44.1% equity and 55.9% long-term debt at September 30, 2024.
Current interest rate trends may result in lower interest costs associated with the Company's variable rate debt in 2026.
Management regularly evaluates the Company’s liquidity through a review of its available financing resources and its cash flows. Resources maintains the ability to raise equity capital through its ATM program, private placement or other public offerings. Roanoke Gas has a term note in the principal amount of $15 million coming due in August 2026. Management believes Roanoke Gas has access to sufficient financing resources to meet its cash requirements for the next year, including cash from operations and the line of credit. Roanoke Gas may also adjust capital spending as necessary, if such a need would arise.
With the MVP now in service, Midstream's future cash requirements will relate to regular monthly operating expenses, debt service and capital contributions. The Company received four quarterly cash distributions from MVP in fiscal 2025 totaling approximately $3.6 million, and should receive similar quarterly distributions going forward. On September 5, 2025, Midstream established a new $53.6 million term note with two banks, which refinanced and replaced all of Midstream's outstanding debt. This term note matures on September 5, 2032. Also on September 5, 2025, Midstream entered into a new Loan Agreement for the MVP Southgate extension and MVP Boost expansion that can be drawn to principal amounts of $1.85 million and $3.65 million, respectively. These loans mature on September 5, 2030, at which time the outstanding principal balance on each note is due. With the establishment of the new term note, Midstream's total debt principal payments over the succeeding 12 months is $2,846,018. Management believes that it will be able to meet Midstream's cash requirements over the ensuing 12-month period with availability on the Southgate and Boost Loan Agreements and its quarterly cash distributions from MVP.
Notes 6 and 7 of the consolidated financial statements provide details on the Company's line-of-credit and borrowing activities.
ATM Program
The Company opted to not utilize the ATM program for the year ended September 30, 2025, although it remains in place. Resources issued 129,164 shares of common stock for $2,635,200, net of $67,569 in fees, under the ATM program for the year ended September 30, 2024.
Off-Balance Sheet Arrangements
The Company has no off-balance sheet arrangements as defined in Regulation S-K, Item 303(a)(4)(ii).
Equity Investment in Mountain Valley Pipeline
The Company owns a less than 1% interest in the LLC that owns and operates the MVP, as defined in its operating agreement. The Company accounts for its interest in the LLC under the equity method of accounting given the LLC maintains specific ownership accounts for each investor, and also considering the Company's rights under the LLC management agreement and the Company's involvement as a stakeholder of the MVP. The Company has been using the equity method since the inception of its investment in fiscal 2016.
From inception through May 2024, earnings from the LLC were primarily attributable to AFUDC income. With the MVP in operation, the Company recognizes its share of earnings from the LLC, favorably adjusted for a basis difference between the Company's proportional share of assets and its carrying value that arose when the Company recorded an other-than-temporary impairment of its investment in 2022. This basis difference amortization is a favorable non-cash adjustment over the operational life of the MVP, or 40 years. During fiscal 2025 and 2024, the Company recorded equity in earnings of consolidated affiliates of approximately $3.2 million and $3.9 million, respectively, with the 2024 amounts being primarily derived from AFUDC. The LLC began to return excess cash in fiscal 2025. Midstream received quarterly cash distributions of its share from the LLC totaling approximately $3.6 million during fiscal 2025, which was a return on its invested capital. Future quarterly distributions are expected to be of a similar magnitude. The Company is using this cash to pay interest and other expenditures related to Midstream. The Company refinanced all of the debt supporting its investment in the MVP in September 2025, as described in the liquidity section above.
Regulatory
See Note 4 of the consolidated financial statements for discussion on Regulatory matters.
Critical Accounting Estimates
The consolidated financial statements of Resources are prepared in accordance with GAAP. The amounts of assets, liabilities, revenues and expenses reported in the Company’s financial statements are affected by accounting policies, estimates and assumptions that are necessary to comply with generally accepted accounting principles. Estimates used in the financial statements are derived from prior experience, statistical analysis and management and professional judgments. Actual results may differ significantly from these estimates and assumptions.
The Company considers an estimate to be critical if it is material to the financial statements and requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate are reasonably likely to occur from period to period. The Company considers the following accounting policies and estimates to be critical.
Regulatory accounting - The Company’s regulated operations follow the accounting and reporting requirements of ASC 980, Regulated Operations. The economic effects of regulation can result in a regulated company deferring costs that have been or are expected to be recovered from customers in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as regulatory assets on the consolidated balance sheet and recorded as expenses in the consolidated statements of income and comprehensive income when such amounts are reflected in rates. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from customers and for current collection in rates of costs that are expected to be incurred in the future.
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 Company would remove the applicable regulatory assets or liabilities from the consolidated balance sheet and include them in the consolidated statements of income and comprehensive income for the period in which the discontinuance occurred.
Unbilled revenue recognition - The Company bills its regulated natural gas customers on a monthly cycle. The billing cycle for most customers does not coincide with the accounting periods used for financial reporting. The Company accrues revenue for estimated natural gas delivered to customers but not yet billed during the accounting period. The following month, the unbilled estimate is reversed, the actual usage is billed and a new unbilled estimate is calculated. The consolidated financial statements include unbilled revenue of $1,373,512 and $1,294,798 as of September 30, 2025 and 2024, respectively. Because the process is performed monthly, the Company routinely ensures its methodology continues to provide a reasonable estimate.
Pension and Postretirement Benefits - The Company offers a pension plan and a postretirement plan to eligible employees. The expenses and liabilities associated with these plans, as disclosed in Note 12 of the consolidated financial statements, are based on numerous assumptions and factors, including provisions of the plans, employee demographics, contributions made to the plan, return on plan assets and various actuarial calculations, assumptions and accounting requirements. Demographic assumptions include projections of future mortality rates, pay increases and retirement patterns, as well as projected health care costs. In regard to the pension plan, specific factors include assumptions regarding the discount rate used in determining future benefit obligations, expected long-term rate of return on plan assets, compensation increases and life expectancies. Similarly, the postretirement medical plan also requires the estimation of many of the same factors as the pension plan in addition to assumptions regarding the rate of medical inflation and Medicare availability. Actual results may differ materially from the results expected from the actuarial assumptions due to changing economic conditions, differences in actual returns on plan assets, different rates of medical inflation, volatility in interest rates and changes in life expectancy. Such differences may result in a material impact on the amount of expense recorded in future periods or the value of the obligations on the consolidated balance sheet.
In selecting the discount rate to be used in determining the benefit liability, the Company utilized the FTSE Pension Discount Curve, which incorporates the rates of return on high-quality, fixed-income investments that corresponded to the length and timing of benefit streams expected under both the pension plan and postretirement plan. The Company used a discount rate of 5.29% and 5.16% for valuing its pension plan liability and postretirement plan liability, respectively, at September 30, 2025. These discount rates represent an increase from the 4.83% rate used for valuing the corresponding liabilities for both the pension plan and postretirement plan at September 30, 2024. The increase in discount rates corresponds to the market reactions to the continuing inflationary pressures on the financial markets and economy. The yield on the 30-year Treasury increased from 4.14% at September 30, 2024 to 4.73% at September 30, 2025. Corporate bond rates experienced a smaller increase as credit spreads have narrowed. The rise in the discount rates was the primary factor in the reduction of the benefit obligations for both the pension and the postretirement plan. Mortality assumptions were based on the PRI-2012 Mortality Table with improvements projected generational using Projection Scale MP-2021 for the current year valuation.
The Company has focused on minimizing the financial risk associated with these plans. With the soft freezes of both the pension and postretirement plans, future liability growth associated with participant service and compensation has been limited. Since January 2017, when the pension plan froze access to new employees, the target asset allocation has transitioned from 60% equity and 40% fixed income to 25% equity and 75% fixed. During the same period, the fixed income portion of the plan was transitioned to an LDI approach, with the fixed income assets invested in securities with a duration that corresponds to the duration of the corresponding liability. This synchronization of the pension assets with the pension liabilities has reduced volatility in the funded status of the plan. This is evidenced by the relative stability of the funded status of the pension plan at September 30, 2025 and 2024 with a funded ratio of 103% and 104%, respectively. The 25% allocation to equity investments provides asset growth potential to offset increases in the pension liability related to those employees continuing to accrue benefits. Management will continue to evaluate the investment allocation as the liabilities mature and make adjustments as necessary.
The Company has initiated a transition of the postretirement plan assets from a 50% equity and 50% fixed income allocation to a 30% equity and 70% fixed income allocation. This revision to the investment targets is in response to a greater proportion of participants that have transitioned to retirement. Similar to the pension plan, the revision to the asset allocation will seek to reduce the volatility in funded status while still providing the opportunity for asset growth through the equity portion of the portfolio. The funded status for the postretirement plan was 147% and 139% as of September 30, 2025 and 2024, respectively. The improvement in the funded status was due to stronger-than-expected market performance only partially offset by higher liabilities as the Company is effectively matching durations within the portfolio. Management will continue to monitor and evaluate the asset allocation and adjust as warranted.
A summary of the funded status of both the pension and postretirement plans is provided below:
Funded status - September 30, 2025
Pension
Postretirement
Total
Benefit obligation
$ 29,480,020
$ 10,462,318
$ 39,942,338
Fair value of assets
30,487,401
15,390,822
45,878,223
Funded status
$ 1,007,381
$ 4,928,504
$ 5,935,885
Funded status - September 30, 2024
Pension
Postretirement
Total
Benefit obligation
$ 29,873,428
$ 10,842,455
$ 40,715,883
Fair value of assets
31,054,138
15,078,281
46,132,419
Funded status
$ 1,180,710
$ 4,235,826
$ 5,416,536
The Company annually evaluates the long-term rate of return on its targeted investment allocation model, as well as the overall asset allocation of its benefit plans, and reviews both plans' potential long-term rate of return assumptions with its investment advisors to determine the rates used in each plan's actuarial calculations. The long-term rates of return increased slightly from 4.95% in fiscal 2024 to 5.75% for fiscal 2025 for both the pension plan and the postretirement plan. Management evaluates the return assumptions and asset allocation and adjusts both as market conditions warrant.
Management estimates that the Company will have no minimum funding requirements next year. The Company currently does not expect to make contributions to its pension plan and postretirement plan in fiscal 2026 due to the funded position of the plans. The Company will continue to evaluate its benefit plan funding levels in light of funding requirements and ongoing investment returns and make adjustments, as necessary, to avoid benefit restrictions and minimize PBGC premiums.
The following schedule reflects the sensitivity of pension costs to changes in certain actuarial assumptions, assuming that the other components of the calculation remain constant.
Actuarial Assumptions - Pension Plan
Change in Assumption
Increase in Pension Cost
Increase in Projected Benefit Obligation
Discount rate
-0.25 %
$ 102,000
$ 946,000
Rate of return on plan assets
-0.25 %
74,000
N/A
Rate of increase in compensation
0.25 %
48,000
225,000
The following schedule reflects the sensitivity of postretirement benefit costs from changes in certain actuarial assumptions, while the other components of the calculation remain constant.
Actuarial Assumptions - Postretirement Plan
Change in Assumption
Increase in Postretirement Benefit Cost
Increase in Accumulated Postretirement Benefit Obligation
Discount rate
-0.25 %
$ 5,000
$ 266,000
Rate of return on plan assets
-0.25 %
38,000
N/A
Medical claim cost increase
0.25 %
31,000
262,000
Derivatives - The Company may hedge certain risks incurred in its operation through the use of derivative instruments. The Company applies the requirements of ASC 815, Derivatives and Hedging, which requires the recognition of derivative instruments as assets or liabilities in the Company’s consolidated balance sheet at fair value. In most instances, fair value is based upon quoted futures prices for natural gas commodities and interest rate futures for interest rate swaps. Changes in the commodity and futures markets will impact the estimates of fair value in the future. Furthermore, the actual market value at the point of realization of the derivative may be significantly different from the values used in determining fair value in prior financial statements. The Company had six interest-rate swaps outstanding at September 30, 2025 related to its variable rate notes, compared to four at September 31, 2024. The corresponding fair value of the swaps is reflected on the consolidated balance sheets as of September 30, 2025 and 2024. A 25 basis point decrease or increase on the yield curve would result in an approximately $600,000 corresponding decrease or increase in the fair value of the interest rate swaps on the balance sheet. See Notes 1 and 8 to the consolidated financial statements for additional information regarding the swaps.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Not applicable.
Item 7B. Insider Trading Policy.
The information set forth under "Compensation Philosophy and Objectives" in the Proxy Statement for the 2026 Annual Meeting of Shareholders of Resources is incorporated herein by reference.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data.
RGC Resources, Inc. and Subsidiaries
Consolidated Financial Statements
for the Years Ended September 30, 2025 and 2024
and Report of Independent
Registered Public Accounting Firm
RGC RESOURCES, INC. AND SUBSIDIARIES
Page
Report of Independent Registered Public Accounting Firm (PCAOB ID 34)
Consolidated Financial Statements for the Years Ended September 30, 2025 and 2024:
Consolidated Balance Sheets
Consolidated Statements of Income
Consolidated Statements of Comprehensive Income (Loss)
Consolidated Statements of Stockholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Deloitte & Touche LLP
901 E. Byrd St. Suite 820
Richmond, VA 23219 USA
www.deloitte.com
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of RGC Resources, Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of RGC Resources, Inc. and subsidiaries (the “Company”) as of September 30, 2025 and 2024, the related consolidated statements of income, comprehensive income (loss), stockholders’ equity, and cash flows, for each of the two years in the period ended September 30, 2025, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of September 30, 2025 and 2024, and the results of its operations and its cash flows for each of the two years in the period ended September 30, 2025, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Rate Regulated Basis of Accounting and Regulatory Matters -Refer to Notes 1 and 4, respectively, to the financial statements
Critical Audit Matter Description
The Company, through its regulated natural gas distribution utility subsidiary, is subject to rate regulation by the Virginia State Corporation Commission (the “SCC”) and follows the accounting and reporting requirements of ASC 980, Regulated Operations. The economic effects of regulation can result in a regulated company deferring costs that have been or are expected to be recovered from customers in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this situation occurs, costs are deferred as assets in the consolidated balance sheet and recorded as expenses when such amounts are reflected in rates. Similarly, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for current collection in rates of costs that are expected to be incurred in the future. In the event the provisions of ASC 980 no longer apply to any or all regulatory assets or liabilities, the Company would write off such amounts and include them in the consolidated statements of income and comprehensive income in the period which ASC 980 no longer applied.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and subjectivity involved in assessing the potential impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery of regulatory assets through future rates, and (2) whether a regulatory liability is due to customers. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the SCC, auditing these judgments requires specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures to evaluate the accounting for the effects of cost-based rate regulation, including the probable recovery or refund of regulatory assets and liabilities, included the following, among others:
●
We obtained and evaluated an analysis from management describing the orders and filings that support management’s assertions regarding the probability of recovery for certain regulatory assets or refund or future reduction in rates for certain regulatory liabilities to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
●
We read and evaluated relevant regulatory orders issued by the SCC for the Company, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess whether this information was properly considered by management in concluding upon the financial statement impacts of rate regulation.
●
For regulatory matters in process, we inspected associated documents and testimony filed with the SCC for any evidence that might contradict management’s assertions.
●
We read and evaluated the minutes of the Board of Directors of the Company for discussions of changes in legal, regulatory, or business factors which could impact management’s conclusions with respect to the impact of rate regulation.
●
We evaluated the Company’s disclosures related to the impacts of rate regulation, including regulatory developments.
/s/ Deloitte & Touche LLP
Richmond, Virginia
December 3, 2025
We have served as the Company's auditor since 2024.
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF September 30, 2025 AND 2024
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
$ 2,320,369 $ 894,185
Accounts receivable, net
4,836,982 4,483,739
Inventories
2,018,316 1,799,631
Gas in storage
8,097,586 8,491,490
Prepaid income taxes
1,618,560 2,362,069
Regulatory assets
2,582,838 5,103,910
Interest rate swaps
828,573 871,026
Other
1,015,967 1,066,251
Total current assets
23,319,191 25,072,301
UTILITY PROPERTY:
In service
366,843,353 345,864,008
Accumulated depreciation and amortization
(100,131,084 ) (92,462,376 )
In service, net
266,712,269 253,401,632
Construction work in progress
8,201,314 8,639,822
Utility property, net
274,913,583 262,041,454
OTHER NON-CURRENT ASSETS:
Regulatory assets
3,315,082 4,445,044
Investment in unconsolidated affiliates
20,723,697 21,057,222
Benefit plan assets
5,935,885 5,416,536
Deferred income taxes
617,390 771,746
Interest rate swaps
421,511 1,191,526
Other
593,227 703,394
Total other non-current assets
31,606,792 33,585,468
TOTAL ASSETS
$ 329,839,566 $ 320,699,223
(Continued)
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF September 30, 2025 AND 2024
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt
$ 2,846,018 $ 800,000
Line-of-credit
- 11,166,181
Dividends payable
2,145,558 2,050,286
Accounts payable
7,085,817 5,429,703
Customer credit balances
1,891,161 1,915,859
Customer deposits
1,537,311 1,488,113
Accrued expenses
5,312,204 4,988,281
Regulatory liabilities
1,638,911 834,278
Interest rate swaps
57,144 -
Other
25,600 25,729
Total current liabilities
22,539,724 28,698,430
LONG-TERM DEBT:
Notes payable
134,258,197 136,955,000
Line-of-credit
11,916,760 -
Unamortized debt issuance costs
(405,794 ) (282,092 )
Long-term debt, net
145,769,163 136,672,908
DEFERRED CREDITS AND OTHER NON-CURRENT LIABILITIES:
Asset retirement obligations
11,640,435 11,142,095
Regulatory cost of retirement obligations
15,869,691 14,409,847
Benefit plan liabilities
201,194 113,600
Deferred income taxes
2,277,550 1,890,562
Regulatory liabilities
17,371,430 19,326,567
Interest rate swaps
298,016 -
Other
319,573 308,439
Total deferred credits and other non-current liabilities
47,977,889 47,191,110
COMMITMENTS AND CONTINGENCIES (Note 14)
STOCKHOLDERS' EQUITY:
Common stock, $5 par value; authorized 20,000,000 shares; issued and outstanding 10,338,308 and 10,249,899 shares in 2025 and 2024, respectively
51,691,540 51,249,495
Preferred stock, no par; authorized 5,000,000 shares; no shares issued and outstanding in 2025 and 2024
- -
Capital in excess of par value
49,311,486 47,988,270
Retained earnings
12,288,032 7,572,439
Accumulated other comprehensive income
261,732 1,326,571
Total stockholders’ equity
113,552,790 108,136,775
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$ 329,839,566 $ 320,699,223
See notes to consolidated financial statements.
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED September 30, 2025 AND 2024
OPERATING REVENUES:
Gas utility
$ 95,231,943
$ 84,533,101
Non utility
102,269
108,131
Total operating revenues
95,334,212
84,641,232
OPERATING EXPENSES:
Cost of gas - utility
42,550,954
35,967,987
Cost of sales - non utility
19,919
24,003
Operations and maintenance
19,911,410
18,354,736
Taxes other than income taxes
2,933,787
2,694,652
Depreciation and amortization
11,470,641
10,518,094
Total operating expenses
76,886,711
67,559,472
OPERATING INCOME
18,447,501
17,081,760
Equity in earnings of unconsolidated affiliate
3,234,632
3,851,871
Other income, net
2,232,883
1,028,761
Interest expense
6,543,511
6,504,885
INCOME BEFORE INCOME TAXES
17,371,505
15,457,507
INCOME TAX EXPENSE
4,091,535
3,696,611
NET INCOME
$ 13,279,970
$ 11,760,896
EARNINGS PER COMMON SHARE:
Basic
$ 1.29
$ 1.16
Diluted
$ 1.29
$ 1.16
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic
10,304,109
10,152,909
Diluted
10,308,686
10,156,480
See notes to consolidated financial statements.
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
YEARS ENDED September 30, 2025 AND 2024
NET INCOME
$ 13,279,970
$ 11,760,896
Other comprehensive income (loss), net of tax:
Interest rate swaps
(867,081 )
(1,897,273 )
Defined benefit plans
(197,758 )
970,555
OTHER COMPREHENSIVE LOSS, NET OF TAX
(1,064,839 )
(926,718 )
COMPREHENSIVE INCOME
$ 12,215,131
$ 10,834,178
See notes to consolidated financial statements.
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
YEARS ENDED September 30, 2025 AND 2024
Accumulated
Capital in
Other
Total
Common
Excess of
Retained
Comprehensive
Stockholders’
Stock
Par Value
Earnings
Income (Loss)
Equity
BALANCE - SEPTEMBER 30, 2023
$ 50,076,270 $ 44,430,786 $ 3,972,280 $ 2,253,289 $ 100,732,625
Net income
- - 11,760,896 - 11,760,896
Other comprehensive loss
- - - (926,718 ) (926,718 )
Stock-based compensation
- 51,500 - - 51,500
Cash dividends declared ($0.80 per share)
- - (8,160,737 ) - (8,160,737 )
Issuance costs
- (82,793 ) - - (82,793 )
Issuance of common stock (234,645 shares)
1,173,225 3,588,777 - - 4,762,002
BALANCE - SEPTEMBER 30, 2024
$ 51,249,495 $ 47,988,270 $ 7,572,439 $ 1,326,571 $ 108,136,775
Net income
- - 13,279,970 - 13,279,970
Other comprehensive loss
- - - (1,064,839 ) (1,064,839 )
Cash dividends declared ($0.83 per share)
- - (8,564,377 ) - (8,564,377 )
Issuance costs
- (35,078 ) - - (35,078 )
Issuance of common stock (88,409 shares)
442,045 1,358,294 - - 1,800,339
BALANCE - SEPTEMBER 30, 2025
$ 51,691,540 $ 49,311,486 $ 12,288,032 $ 261,732 $ 113,552,790
See notes to consolidated financial statements.
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED September 30, 2025 AND 2024
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income
$ 13,279,970
$ 11,760,896
Adjustments to reconcile net income to net cash provided by operations:
Depreciation and amortization
11,470,641
10,518,094
Cost of retirement of utility property
(512,872 )
(576,771 )
Stock-based compensation
673,057
711,924
Equity in earnings of unconsolidated affiliate
(3,234,632 )
(3,851,871 )
Distributions from unconsolidated affiliate
3,644,542
-
Donated property
(762,240 )
(781,990 )
Deferred income taxes
318,673
(121,781 )
Other noncash items, net
371,170
516,836
Changes in assets and liabilities which provided (used) cash:
Accounts receivable and customer deposits, net
(293,609 )
(275,196 )
Inventories and gas in storage
175,219
2,568,942
Regulatory and other assets
2,935,963
(2,765,027 )
Regulatory liabilities
(405,105 )
(1,006,472 )
Other
1,287,372
736,041
Net cash provided by operating activities
28,948,149
17,433,625
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility property
(20,730,140 )
(22,094,406 )
Investment in unconsolidated affiliates
(76,385 )
(18,258 )
Proceeds from disposal of utility property
72,910
79,032
Net cash used in investing activities
(20,733,615 )
(22,033,632 )
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under line-of-credit
48,597,639
45,388,194
Repayments under line-of-credit
(47,847,060 )
(38,575,585 )
Proceeds from issuance of unsecured notes
17,529,215
10,855,000
Retirement of notes payable
(18,180,000 )
(10,175,000 )
Debt issuance expenses
(184,300 )
(101,206 )
Proceeds from issuance of stock
1,765,261
4,679,209
Cash dividends paid
(8,469,105 )
(8,088,851 )
Net cash provided by (used in) financing activities
(6,788,350 )
3,981,761
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
1,426,184
(618,246 )
BEGINNING CASH AND CASH EQUIVALENTS
894,185
1,512,431
ENDING CASH AND CASH EQUIVALENTS
$ 2,320,369
$ 894,185
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the year for:
Interest
$ 6,350,032
$ 6,273,144
Income taxes
4,195,000
2,940,000
Significant noncash activities:
Accrued capital expenditures
1,378,196
1,257,734
Proceeds and retirement of borrowings with the same financial institution
38,600,000
-
See notes to consolidated financial statements.
RGC RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED September 30, 2025 AND 2024
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation-RGC Resources, Inc. is an energy services company primarily engaged in the sale and distribution of natural gas. The consolidated financial statements include the accounts of Resources and its wholly owned subsidiaries: Roanoke Gas and Midstream. Roanoke Gas is a natural gas utility, which distributes and sells natural gas to approximately 62,500 residential, commercial and industrial customers within its service areas in Roanoke, Virginia and the surrounding localities. The Company’s business is seasonal in nature as a majority of natural gas sales are for space heating during the winter season. Roanoke Gas is regulated by the SCC. Midstream is a wholly owned subsidiary created primarily to invest in the LLC.
The Company follows accounting and reporting standards established by the FASB and the SEC, including certain provisions allowed under the smaller reporting company exceptions.
Rate Regulated Basis of Accounting-The Company’s regulated operations follow the accounting and reporting requirements of ASC 980, Regulated Operations. The economic effects of regulation can result in a regulated company deferring costs that have been or are expected to be recovered from customers in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this situation occurs, costs are deferred as assets in the consolidated balance sheet (regulatory assets) and recorded as expenses when such amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for current collection in rates of costs that are expected to be incurred in the future (regulatory liabilities). In the event the provisions of ASC 980 no longer apply to any or all regulatory assets or liabilities, the Company would write off such amounts and include them in the consolidated statements of income and comprehensive income in the period which ASC 980 no longer applied.
Regulatory assets and liabilities included in the Company’s consolidated balance sheets as of September 30, 2025 and 2024 are as follows:
September 30
Assets:
Current Assets:
Regulatory assets:
Accrued WNA revenues
$ 504,003 $ 919,375
Under-recovery of natural gas costs
750,295 2,690,247
Under-recovery of RNG revenues
1,019,821 1,331,064
Under-recovery of SAVE Plan revenues
265,317 107,678
Accrued pension
30,640 42,785
Other deferred expenses
12,762 12,761
Total current
2,582,838 5,103,910
Other Non-Current Assets:
Regulatory assets:
Premium on early retirement of debt
1,027,684 1,141,872
Accrued pension
2,168,902 2,998,881
Other deferred expenses
118,496 304,291
Total non-current
3,315,082 4,445,044
Total regulatory assets
$ 5,897,920 $ 9,548,954
Liabilities and Stockholders' Equity:
Current Liabilities:
Regulatory liabilities:
Rate refund
$ - $ 37,500
Deferred income taxes
591,764 591,764
Supplier refunds
889,564 30,556
Other deferred liabilities
157,583 174,458
Total current
1,638,911 834,278
Deferred Credits and Non-Current Other Liabilities:
Regulatory cost of retirement obligations
15,869,691 14,409,847
Regulatory liabilities:
Deferred income taxes
13,649,719 15,468,096
Deferred postretirement medical
3,721,711 3,858,471
Total non-current
33,241,121 33,736,414
Total regulatory liabilities
$ 34,880,032 $ 34,570,692
Amortization of $101,141 and $116,085 of regulatory assets for the years ended September 30, 2025 and 2024, respectively, is included in operations and maintenance expense on the consolidated statements of income. Amortization of $131,673 and $211,863 of regulatory assets for the years ended September 30, 2025 and 2024, respectively, is included in other income, net on the consolidated statements of income. Amortization of $114,187 of regulatory assets for both years ended September 30, 2025 and 2024 is included in interest expense on the consolidated statements of income.
As of September 30, 2025, the Company had regulatory assets in the amount of $5,897,920 on which the Company did not earn a return during the recovery period.
Utility Property and Depreciation-Utility property is stated at original cost and includes direct labor and materials, contractor costs, and all allocable overhead charges. The Company applies the group method of accounting, where the costs of like assets are aggregated and depreciated by applying a rate based on the average expected useful life of the assets. In accordance with Company policy, expenditures for depreciable assets with a life greater than one year are capitalized, along with any upgrades or improvements to existing assets, when such upgrades or improvements significantly improve or extend the original expected useful life. Expenditures for maintenance, repairs, and minor renewals and betterments are expensed as incurred. The original cost of depreciable property retired is removed from utility property and charged to accumulated depreciation. The cost of asset removals, less salvage, is charged to “regulatory cost of retirement obligations” or “asset retirement obligations” as explained under Asset Retirement Obligations below.
Utility property is composed of the following major classes of assets:
September 30
Distribution and transmission
$ 330,895,437 $ 312,999,348
LNG storage
15,863,849 15,437,447
General and miscellaneous
20,084,067 17,427,213
Total utility property in service
$ 366,843,353 $ 345,864,008
Provisions for depreciation are computed principally at composite straight-line rates over a range of periods. Rates are determined by depreciation studies, which are required to be performed at least every 5 years on the regulated utility assets of Roanoke Gas. The most recent depreciation study was completed and approved by the SCC staff in fiscal 2024. The composite weighted-average depreciation rate was 3.26% for both years ended September 30, 2025 and 2024.
The composite rates are composed of two components, one based on average service life and one based on cost of retirement. As a result, the Company accrues the estimated cost of retirement of long-lived assets through depreciation expense. These retirement costs are not a legal obligation but rather the result of cost-based regulation and are accounted for under the provisions of ASC 980. Such amounts are classified as a regulatory liability.
The Company reviews long-lived assets and certain identifiable intangibles for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. These reviews have not identified any impairments which would have a material effect on the results of operations or financial condition.
From time to time, the Company recognizes AFUDC related to large infrastructure investments. This treatment allows capitalizing both the equity and debt financing costs during the construction phases. The Company did not capitalize any financing costs related to projects for the years ended September 30, 2025 and 2024.
Asset Retirement Obligations-ASC 410, Asset Retirement and Environmental Obligations, requires entities to record the fair value of a liability for an ARO when there exists a legal obligation for the retirement of the asset. When the liability is initially recorded, the entity capitalizes the cost, thereby increasing the carrying amount of the underlying asset. In subsequent periods, the liability is accreted, and the capitalized cost is depreciated over the useful life of the underlying asset. The Company has recorded AROs for its future regulatory obligations related to purging and capping its distribution mains and services upon retirement, although the timing of such retirements is uncertain.
The following is a summary of the AROs:
Years Ended September 30
Beginning balance
$ 11,142,095 $ 10,792,831
Liabilities incurred
72,502 86,483
Liabilities settled
(138,391 ) (168,913 )
Accretion
564,229 582,383
Revisions to estimates and other
- (150,689 )
Ending balance
$ 11,640,435 $ 11,142,095
Cash, Cash Equivalents and Short-Term Investments-From time to time, the Company will have balances on deposit at banks in excess of the amount insured by the FDIC. The Company has not experienced any losses on these accounts and does not consider these amounts to be at risk. For purposes of the consolidated statements of cash flows, the Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents.
Customer Receivables and Allowance for Credit Losses-Accounts receivable include amounts billed to customers for natural gas sales and related services and gas sales occurring subsequent to normal billing cycles but before the end of the period. The Company provides an estimate for losses on these receivables by utilizing historical information, current account balances, account aging and current economic conditions. Customer accounts are charged off annually when deemed uncollectible or when turned over to a collection agency for action.
A reconciliation of changes in the allowance for credit losses is as follows:
Years Ended September 30
Beginning balance
$ 153,347 $ 155,164
Provision for credit losses
278,606 110,676
Recoveries of accounts written off
140,727 173,660
Accounts written off
(429,769 ) (286,153 )
Ending balance
$ 142,911 $ 153,347
Lease Accounting-The Company leases certain assets including office space and land classified as operating leases. The Company determines if an arrangement is a lease at inception of the agreement based on the terms and conditions in the contract. The operating lease ROU assets and operating lease liabilities are recognized as the present value of the future minimum lease payments over the lease term at commencement date. As most of the leases do not provide an implicit rate, the Company uses an estimate of its secured incremental borrowing rate based on the information available at commencement date in determining the present value of future payments. The incremental borrowing rate is determined by management aided by inquiries of a third party. The operating lease ROU asset also is adjusted for any lease payments made and excludes lease incentives and initial direct costs incurred. The Company’s lease terms may include options to extend or terminate the lease at certain dates, typically at the Company’s own discretion. The Company regularly evaluates the renewal options and when they are reasonably certain of exercise, the Company includes the renewal period in its lease term. Lease expense for minimum lease payments is recognized on a straight-line basis over the term of the agreement. The Company made an accounting policy election that payments under agreements with an initial term of 12 months or less will not be included on the consolidated balance sheet but will be recognized in the consolidated statements of operations on a straight-line basis over the term of the agreement.
Inventories-Natural gas in storage and materials and supplies inventories are recorded at average cost. Natural gas storage injections are priced at the purchase cost at the time of injection and storage withdrawals are priced at the weighted average cost of gas in storage. Materials and supplies are removed from inventory at average cost.
Unbilled Revenues-The Company bills its natural gas customers on a monthly cycle; however, the billing cycle for most firm customers does not coincide with the accounting periods used for financial reporting. As the Company recognizes revenue when gas is delivered, an accrual is made to estimate revenues for natural gas delivered to customers but not billed during the accounting period. The amounts of unbilled revenue receivable included in accounts receivable on the consolidated balance sheets at September 30, 2025 and 2024 were $1,373,512 and $1,294,798, respectively.
Income Taxes-Income taxes are accounted for using the asset and liability method. Under the asset and liability method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the years in which those temporary differences are expected to be recovered or settled. A valuation allowance against deferred tax assets is provided if it is more likely than not the deferred tax asset will not be realized. The Company and its subsidiaries file consolidated state and federal income tax returns.
Debt Expenses-Debt issuance expenses are deferred and amortized over the lives of the debt instruments. The unamortized balances are offset against the carrying value of long-term debt.
Over/Under-Recovery of Natural Gas Costs-From time to time, the Company enters into forward purchases of natural gas at fixed prices through its asset manager. As management believes it is probable these purchases will physically settle, the Company has applied the normal purchase and normal sale exception to derivative accounting. Pursuant to the provisions of the Company’s PGA clause, the SCC provides the Company with a method of passing along to its customers increases or decreases in natural gas costs incurred by its regulated operations, including gains and losses on natural gas derivative hedging instruments, if utilized. On at least a quarterly basis, the Company files a PGA rate adjustment request with the SCC to increase or decrease the gas cost component of its rates, based on projected price and activity. Once administrative approval is received, the Company adjusts the gas cost component of its rates to reflect the approved amount. As actual costs and usage will differ from the projections used in establishing the PGA rate, the Company may either over-recover or under-recover its actual gas costs during the period. Any difference between actual costs incurred and costs recovered through the application of the PGA is recorded as a regulatory asset or liability. At the end of the deferral period, the balance of the net deferred charge or credit is amortized over an ensuing 12-month period as amounts are reflected in customer bills.
Fair Value-Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between willing market participants at the measurement date. The Company determines fair value based on the following fair value hierarchy which prioritizes each input to the valuation methods into one of the following three broad levels:
•
Level 1 - Unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.
•
Level 2 - Inputs other than quoted prices in Level 1 that are either for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, or inputs that are derived principally from or corroborated by observable market data by correlation or other means.
•
Level 3 - Unobservable inputs for the asset or liability where there is little, if any, market activity which require the Company to develop its own assumptions.
The fair value hierarchy gives the highest priority to unadjusted quoted prices in active markets (Level 1) and the lowest priority to unobservable inputs (Level 3). All fair value disclosures are categorized within one of the three categories in the hierarchy based on the lowest level that is significant to the valuation. See fair value disclosures below and in Notes 8 and 12.
Use of Estimates-The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Excise and Sales Taxes-Certain excise and sales taxes imposed by the state and local governments in the Company’s service territory are collected by the Company from its customers. These taxes are passed through to the state and local governments and included within accounts payable on the Company's consolidated balance sheets.
Earnings Per Share-Basic EPS and diluted EPS are calculated by dividing net income by the weighted-average common shares outstanding during the period and the weighted-average common shares outstanding during the period plus potential dilutive common shares, respectively. Potential dilutive common shares are calculated in accordance with the treasury stock method, which assumes that proceeds from the exercise of all options are used to repurchase common stock at market value. The amount of shares remaining after the proceeds are exhausted represents the potentially dilutive effect of the securities. The computation of diluted EPS for the years ended September 30, 2025 and 2024 excludes potentially dilutive shares of 1,926 and 2,542, respectively, because to include them would be antidilutive for the period. However, these shares could potentially dilute EPS in the future. A reconciliation of basic and diluted EPS is presented below:
Years Ended September 30
Net income
$ 13,279,970 $ 11,760,896
Weighted-average common shares
10,304,109 10,152,909
Effect of dilutive securities:
Options to purchase common stock
4,577 3,571
Diluted average common shares
10,308,686 10,156,480
Earnings per share of common stock:
Basic
$ 1.29 $ 1.16
Diluted
$ 1.29 $ 1.16
Business and Credit Concentrations-The primary business of the Company is the distribution of natural gas to residential, commercial and industrial customers in its service territories.
No sales to individual customers accounted for more than 5% of total revenue in any period. No individual customer amounted to more than 5% of total accounts receivable at September 30, 2025 and 2024.
Roanoke Gas currently holds the only franchises and/or CPCNs to distribute natural gas in its service area. These franchises generally extend for multi-year periods, are renewable by the municipalities and are intended for perpetual duration, including exclusive franchises in the cities of Roanoke, Salem and the Town of Vinton. All franchises are set to expire December 31, 2035.
Roanoke Gas is currently served by three primary pipelines that provide the natural gas supplied to the Company’s customers. Depending upon weather conditions and the level of customer demand, failure of one or all of these transmission pipelines could have a major adverse impact on the Company.
Derivative and Hedging Activities-ASC 815, Derivatives and Hedging, requires the recognition of all derivative instruments as assets or liabilities in the Company’s consolidated balance sheet and measurement of those instruments at fair value.
The Company’s hedging and derivatives policy allows management to enter into derivatives for the purpose of managing the commodity and financial market risks of its business operations. The Company’s hedging and derivatives policy specifically prohibits the use of derivatives for speculative purposes. The key market risks that the Company may hedge against include the price of natural gas and the cost of borrowed funds.
From time to time, the Company has entered into collars, swaps and caps for the purpose of hedging the price of natural gas in order to provide price stability during the winter months. The fair value of these instruments is recorded in the consolidated balance sheets with the offsetting entry to either under- or over-recovery of gas costs. Net income and other comprehensive income are not affected by the change in market value as any cost incurred or benefit received from these instruments is recoverable or refunded through the PGA as the SCC allows for full recovery of prudent costs associated with natural gas purchases. At September 30, 2025 and 2024, the Company had no outstanding derivative instruments for the purchase of natural gas.
The Company has six interest rate swaps associated with certain of its variable rate debt. Roanoke Gas has two variable rate term notes in the amounts of $15 million and $10 million, with corresponding swap agreements to convert the variable interest rates into fixed rates of 2.00% and 2.49%, respectively. Midstream has four swap agreements in the amounts of $14 million, $4 million, $20.6 million, and $15 million, corresponding to the $53.6 million variable rate term note. The swap agreements convert the note into a fixed rate instrument with effective interest rates of 3.24%, 2.443%, 5.061%, and 5.061%, respectively. The swaps qualify as cash flow hedges with changes in fair value reported in other comprehensive income. No portion of the swaps were deemed ineffective during the periods presented.
See Notes 7 and 8 for additional information on the swaps and fair value.
Other Comprehensive Income (Loss)-A summary of other comprehensive income is provided below:
Tax
Before Tax
(Expense)
Net of Tax
Amount
or Benefit
Amount
Year Ended September 30, 2025:
Interest rate swaps:
Unrealized gains
$ 207,015 $ (53,287 ) $ 153,728
Transfer of realized gains to interest expense
(1,374,643 ) 353,834 (1,020,809 )
Net interest rate swaps
(1,167,628 ) 300,547 (867,081 )
Defined benefit plans:
Net losses arising during period
(282,941 ) 72,828 (210,113 )
Amortization of actuarial losses
16,638 (4,283 ) 12,355
Net defined benefit plans
(266,303 ) 68,545 (197,758 )
Other comprehensive loss
$ (1,433,931 ) $ 369,092 $ (1,064,839 )
Year Ended September 30, 2024:
Interest rate swaps:
Unrealized losses
$ (554,778 ) $ 142,800 $ (411,978 )
Transfer of realized gains to interest expense
(2,000,126 ) 514,831 (1,485,295 )
Net interest rate swaps
(2,554,904 ) 657,631 (1,897,273 )
Defined benefit plans:
Net gains arising during period
1,233,462 (317,492 ) 915,970
Amortization of actuarial losses
73,505 (18,920 ) 54,585
Net defined benefit plans
1,306,967 (336,412 ) 970,555
Other comprehensive loss
$ (1,247,937 ) $ 321,219 $ (926,718 )
The amortization of actuarial gains or losses are included as a component of net periodic pension and postretirement benefit costs under other income, net in the consolidated statements of income.
Composition of AOCI:
Interest Rate Swaps
Defined Benefit Plans
Accumulated Other Comprehensive Income (Loss)
Balance September 30, 2023
$ 3,428,922 $ (1,175,633 ) $ 2,253,289
Other comprehensive income (loss)
(1,897,273 ) 970,555 (926,718 )
Balance September 30, 2024
1,531,649 (205,078 ) 1,326,571
Other comprehensive loss
(867,081 ) (197,758 ) (1,064,839 )
Balance September 30, 2025
$ 664,568 $ (402,836 ) $ 261,732
Recently Adopted Accounting Standards
In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280) - Improvements to Reportable Segment Disclosures, which enhances and expands the current annual and interim requirements on segment information disclosures. The new guidance requires disclosure of significant segment expenses that are regularly provided to the chief operating decision maker (CODM) and included within each reported measure of segment profit or loss, an amount and description of the composition of other segment items to reconcile to segment profit or loss, and the title and position of the entity's CODM. The provisions within the guidance are to be applied retrospectively for all comparative periods and are effective for the Company for the fiscal year that began October 1, 2024 and interim periods within fiscal year beginning October 1, 2025. The Company adopted ASU 2023-07 effective for the year ended September 30, 2025, with retrospective application of the additional segment information for the year ended September 30, 2024. Additional information regarding the Company's reportable segments is included in Note 3 to the consolidated financial statements, with no impact on results of operations, cash flows, or financial condition of the Company.
Recently Issued Accounting Standards
In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The new guidance requires that on an annual basis public business entities disclose specific categories in the rate reconciliation table and provide additional information for reconciling items that meet a quantitative threshold (items equal to or greater than 5 percent of the amount computed by multiplying pretax income or loss by the applicable statutory rate). The required disclosures will provide more granularity regarding the payment of income taxes to federal, state and foreign entities. The Company does not expect certain requirements of this ASU to have a significant impact to its current disclosures as all of its operations are domestic and reside in two states. Changes to the rate reconciliation table will result in additional disclosure. The new guidance is effective for the Company for annual periods beginning October 1, 2025.
In November 2024, the SEC issued ASU 2024-03, Income Statement - Reporting Comprehensive Income (Topic 220): Expense Disaggregation Disclosures. The new guidance requires public business entities to disclose certain additional detail about expenses including, among other items, purchases of inventory, employee compensation, depreciation and intangible asset amortization included within each income statement expense line items within continuing operations. The guidance also requires disclosure of the total amount of selling expenses and the Company’s definition of selling expenses. Such disclosures must be made on an annual and interim basis and integrated with existing disclosure requirements in a tabular format in the footnotes to the financial statements. Further, in January 2025, the FASB issued ASU 2025-01, Income Statement - Reporting Comprehensive Income (Topic 220): Expense Disaggregation Disclosures: Clarifying the Effective Date, which clarified the effective date of ASU 2024-03. The new guidance is effective for the Company for annual periods beginning October 1, 2027 and interim periods within fiscal year beginning October 1, 2028. The Company is currently assessing the impacts of the new guidance on its financial statement disclosures.
Other accounting standards that have been issued or proposed by the FASB or other standard-setting bodies are not currently applicable to the Company or are not expected to have a significant impact on the Company’s financial position, results of operations and cash flows.
Reclassification
Certain prior year amounts have been reclassified to conform to current year presentations.
2.
REVENUE
The Company assesses new contracts and identifies related performance obligations for promises to transfer distinct goods or services to the customer. Revenue is recognized when performance obligations have been satisfied. In the case of Roanoke Gas, the Company contracts with its customers for the sale and/or delivery of natural gas.
The following tables summarize revenue by customer, product and income statement classification for the years ended September 30:
Gas utility
Non utility
Total operating revenues
Natural Gas (Billed and Unbilled):
Residential
$ 54,093,809 $ - $ 54,093,809
Commercial
33,035,454 - 33,035,454
Transportation and Interruptible
5,871,389 - 5,871,389
Other
791,194 102,269 893,463
Total contracts with customers
93,791,846 102,269 93,894,115
Alternative revenue programs
1,440,097 - 1,440,097
Total operating revenues
$ 95,231,943 $ 102,269 $ 95,334,212
Gas utility
Non utility
Total operating revenues
Natural Gas (Billed and Unbilled):
Residential
$ 46,472,676 $ - $ 46,472,676
Commercial
27,659,507 - 27,659,507
Transportation and Interruptible
5,414,157 - 5,414,157
Other
879,186 108,131 987,317
Total contracts with customers
80,425,526 108,131 80,533,657
Alternative revenue programs
4,107,575 - 4,107,575
Total operating revenues
$ 84,533,101 $ 108,131 $ 84,641,232
Gas utility revenues
Substantially all of Roanoke Gas’ revenues are derived from rates authorized by the SCC through its tariffs. Based on its evaluation, the Company has concluded that these tariff-based revenues fall within the scope of ASC 606. Tariff rates represent the transaction price. Performance obligations include the procurement and transport of natural gas through the Company's distribution system to customers. The delivery of natural gas to customers results in the satisfaction of the Company’s respective performance obligations over time.
All customers are billed monthly based on consumption as measured by metered usage with payments due 20 days from the rendering of the bill. Revenue is recognized as bills are issued for natural gas that has been delivered or transported. In addition, the Company utilizes the practical expedient that allows an entity to recognize the invoiced amount as revenue, if that amount corresponds to the value received by the customer. Since customers are billed tariff rates, there is no variable consideration in the transaction price.
Unbilled revenue is included in residential and commercial revenues in the preceding table. Natural gas consumption is estimated for the period subsequent to the last billed date and up through the last day of the month. Estimated volumes and approved tariff rates are utilized to calculate unbilled revenue. The following month, the unbilled estimate is reversed, the actual usage is billed and a new unbilled estimate is calculated. The Company obtains metered usage for transportation and interruptible customers at the end of each month, thereby eliminating any unbilled consideration for these rate classes.
Other revenues
Other revenues primarily consist of miscellaneous fees and charges, utility-related revenues not directly billed to utility customers and billings for non-utility activities. Customers are invoiced monthly based on services provided for these activities. The Company utilizes the practical expedient allowing revenue to be recognized based on invoiced amounts. The transaction price is based on a contractually predetermined rate schedule; therefore, the transaction price represents total value to the customer and no variable price consideration exists.
Alternative revenue program revenues
ARPs, which fall outside the scope of ASC 606, are SCC approved mechanisms that allow for the adjustment of revenues for certain broad, external factors, or for additional billings if the entity achieves certain performance targets. The Company's ARPs include its WNA, which adjusts revenues for the effects of weather temperature variations as compared to the 30-year average; the SAVE Plan over/under collection mechanism, which adjusts revenues for the differences between SAVE Plan revenues billed to customers and the revenues earned, as calculated based on the timing and extent of infrastructure replacement completed during the period; and the RNG over/under collection mechanism, which adjusts revenues similar to the SAVE Plan, but is calculated based on the timing and costs associated with owning, operating and maintaining the RNG facility. These amounts are ultimately collected from, or returned to, customers through future rate changes approved by the SCC.
Customer accounts receivable and liabilities
Accounts receivable, as reflected in the condensed consolidated balance sheets, includes both billed and unbilled customer revenues, as well as amounts that are not related to customers. The balances of customer receivables are provided below:
Current Assets
Current Liabilities
Trade accounts receivable (1)
Unbilled revenue (1)
Customer credit balances
Customer deposits
September 30, 2024
$ 3,080,140 $ 1,294,798 $ 1,915,859 $ 1,488,113
September 30, 2025
3,354,154 1,373,512 1,891,161 1,537,311
Increase (decrease)
$ 274,014 $ 78,714 $ (24,698 ) $ 49,198
(1) Included in "Accounts receivable, net" in the consolidated balance sheet. Amounts shown net of reserve for bad debts.
The Company did not incur any significant costs to obtain contracts during the period. Certain customers elect to pay even amounts monthly, giving rise to assets and liabilities that are in the table above. All amounts clear annually.
3.
SEGMENT INFORMATION
Operating segments are defined as components of an enterprise for which separate financial information is available and is evaluated regularly by the Company's executive management in deciding how to allocate resources and assess performance. The Company has two reportable segments based on the nature of their activities and are defined as follows:
Gas Utility - The natural gas distribution segment of the Company generates revenue from its tariff rates and other regulatory mechanisms through which it provides for the sale and distribution of natural gas to its residential, commercial and industrial customers.
Investment in Affiliates - The investment in affiliates segment reflects the income generated through the activities of the Company's investment in the LLC.
In order to reconcile to net income as disclosed in the consolidated statements of income, "Corporate and other" rows are included below associated with certain unallocated expenses that represent corporate reporting adjustments.
The accounting policies of the reported segments are the same as those described within Note 1. Information is routinely presented to the CODM, the Company's President and Chief Executive Officer, in a manner that makes significant elements of profitability and cash flows of each segment easily discernible. The CODM evaluates the performance of the reportable segments based on the Gas Utility's operating income (loss) and the Investment in Affiliates' equity in earnings, as well as cash flows, and uses these measures to evaluate segment performance and allocate resources, primarily during the annual budget and forecasting processes. The CODM regularly reviews variances between budgeted and actual results in assessing earnings, operational performance, and allocating resources including personnel and capital allocations that affect each reportable segment. When the CODM reviews balance sheet information, it is at a consolidated level. Intersegment transactions are recorded at cost.
Information related to the reportable segments of the Company are provided below:
Gas Utility
Investment in Affiliates
Consolidated Total
For the Year Ended September 30, 2025:
Operating revenues
$ 95,231,943 $ - $ 95,231,943
Corporate and other
- - 102,269
Total revenues
95,231,943 - 95,334,212
Cost of gas - utility
42,550,954 - 42,550,954
Operations and maintenance
19,729,415 181,995 19,911,410
Taxes other than income taxes
2,931,367 2,420 2,933,787
Depreciation and amortization
11,470,641 - 11,470,641
Corporate and other
- - 19,919
Total operating income (loss)
18,549,566 (184,415 ) 18,447,501
Equity in earnings
- 3,234,632 3,234,632
Interest expense
3,706,152 2,837,359 6,543,511
Income before income taxes
17,072,877 216,278 17,289,155
Corporate and other
- - 82,350
Total income before income taxes
$ 17,072,877 $ 216,278 $ 17,371,505
As of September 30, 2025:
Assets
$ 291,571,159 $ 21,679,154 $ 313,250,313
Corporate and other
- - 16,589,253
Total assets
291,571,159 21,679,154 329,839,566
Gross additions to utility property
20,730,140 - 20,730,140
Gross investment in affiliates
$ - $ 76,385 $ 76,385
Gas Utility
Investment in Affiliates
Consolidated Total
For the Year Ended September 30, 2024:
Operating revenues
$ 84,533,101 $ - $ 84,533,101
Corporate and other
- - 108,131
Total revenues
84,533,101 - 84,641,232
Cost of gas - utility
35,967,987 - $ 35,967,987
Operations and maintenance
18,215,354 133,486 $ 18,348,840
Taxes other than income taxes
2,701,186 3,354 $ 2,704,540
Depreciation and amortization
10,518,094 - 10,518,094
Corporate and other
- - 20,011
Total operating income (loss)
17,130,480 (136,840 ) 17,081,760
Equity in earnings
- 3,851,871 3,851,871
Interest expense
3,700,674 2,804,211 6,504,885
Income before income taxes
14,459,009 910,490 15,369,499
Corporate and other
- - 88,008
Total income before income taxes
$ 14,459,009 $ 910,490 $ 15,457,507
As of September 30, 2024:
Assets
$ 280,508,989 $ 21,324,361 $ 301,833,350
Corporate and other
- - 18,865,873
Total assets
280,508,989 21,324,361 320,699,223
Gross additions to utility property
22,094,406 - 22,094,406
Gross investment in affiliates
$ - $ 18,258 $ 18,258
4.
REGULATORY MATTERS
The SCC exercises regulatory authority over the natural gas operations of Roanoke Gas. Such regulation encompasses terms, conditions and rates to be charged to customers for natural gas service, safety standards, service extension and depreciation.
In response to continued inflationary pressures, Roanoke Gas filed a general rate application on February 2, 2024 with the SCC seeking to increase its non-gas base rates by $4.33 million and its permitted return on equity from 9.44% to 10.35% reflecting its higher cost of capital, including higher interest expense. The SCC permitted the Company to implement its new rates on an interim basis for customer billings on or after July 1, 2024, subject to refund. On October 16, 2024, the Company reached a settlement with the SCC staff on all outstanding issues in the case. Under the terms of the settlement, the Company agreed to an annual incremental revenue requirement increase of $4.08 million based on a return on equity of 9.90%. On April 10, 2025, the SCC issued a final order approving the settlement agreement in its entirety. Refunds for the difference in amounts that were billed based on interim and settlement rates, which had previously been accrued, were made to customers in May 2025.
On December 2, 2025, the Company filed a non-gas base rate application with the SCC to increase revenues by $4.3 million annually, with interim rates proposed to customers in the second quarter of fiscal 2026.
On May 30, 2025, Roanoke Gas filed for approval of an updated RNG Rider to become effective October 1, 2025. The RNG Rider recovers costs associated with the RNG facility to produce renewable natural gas that was approved by the SCC in 2022. The revenue requirement associated with the RNG Rider is $1.66 million. The impact to customers is affected by the under-recovered costs during the prior fiscal year, the sale of environmental credits and the over crediting of customers for RIN sales, resulting in a net impact to customers of approximately $699,000. The Company received a final order from the SCC approving the Company's updated RNG Rider on September 26, 2025.
On June 30, 2025, Roanoke Gas filed for approval of an updated annual SAVE Rider to become effective October 1, 2025. The proposed SAVE Rider revenue requirement of $2.64 million is designed to recover the costs associated with an estimated $10.33 million of SAVE eligible investment during fiscal 2026. The revenue requirement also included an adjustment for under-recovered costs incurred during the prior year. The Commission approved the Company’s updated SAVE Rider on September 26, 2025, which contained a slightly lower revenue requirement of $2.61 million.
On June 2, 2022, Roanoke Gas filed an application with the SCC to acquire certain natural gas distribution assets from a local housing authority. Under this application, the Company requested the approval to acquire such facilities at five separate apartment complexes, located in the Company’s service territory, that were under housing authority management. Under the proposed plan, the housing authority would renew existing natural gas distribution facilities to include mains, services, and meter installations and then transfer ownership of these facilities to Roanoke Gas. In turn, Roanoke Gas would assume responsibility for the operation and maintenance of these assets and recognize a gain related to the asset acquisition equal to the cost associated with the renewal. The SCC approved the application in July 2022.
The housing authority completed the transfer of two apartment complexes to Roanoke Gas in fiscal 2022, one complex in fiscal 2023, one complex in fiscal 2024 and the last complex in fiscal 2025. For fiscal years 2024 and 2025, Roanoke Gas recognized pre-tax income of approximately $782,000 and $762,000, respectively, for the assets transferred by analogy to ASC 958. The assets are included under utility property, in service on the consolidated balance sheets and the income is recorded in other income, net on the consolidated statements of income. There are no ongoing obligations between the parties for the properties transferred. Additionally, there are no remaining facilities to be transferred in the future under the plan.
5.
OTHER INVESTMENTS
Midstream has invested less than 1% in the equity interests of the LLC that owns and operates the MVP. The Company accounts for its interest in the LLC under the equity method of accounting given the LLC maintains specific ownership accounts for each investor, and also considering the Company's rights under the LLC management agreement and the Company's involvement as a stakeholder of the MVP. The Company has been using the equity method since the inception of its investment in fiscal 2016. The MVP entered commercial operation on June 14, 2024 and commenced long-term firm capacity obligations on July 1, 2024.
AFUDC attributable to MVP was recognized during the construction phase, and is included in the equity in earnings of unconsolidated affiliate in the tables below. AFUDC on the main pipeline ceased in June 2024 when MVP went into commercial operations; large expansions and improvement projects will give rise to AFUDC in the future.
The Company participates in the earnings of the LLC proportionate to its level of investment, favorably adjusted for a basis difference between the Company's capital account and its carrying value that arose when the Company recorded an other-than-temporary impairment of its investment in 2022. This basis difference amortization is a favorable non-cash adjustment to income over the book life of the MVP, which is 40 years. The Company's share of earnings from the LLC and the basis difference amortization are presented under equity in earnings of unconsolidated affiliate on the consolidated statements of income. The Company received four quarterly cash distributions totaling approximately $3.6 million from the LLC during fiscal 2025 and expects future quarterly distributions to be of a similar magnitude to those received to date.
Midstream assesses the value of its investment in the LLC on at least a quarterly basis, and no impairment indicators were identified in fiscal 2025 or 2024.
Funding for Midstream's investments has been provided through equity contributions from Resources and unsecured promissory notes as detailed in Note 7.
The investments in the LLC are included in the consolidated balance sheets as follows:
September 30
Balance Sheet location:
Other Assets:
MVP
$ 20,538,437 $ 20,948,347
Southgate
185,260 108,875
Investment in unconsolidated affiliates
$ 20,723,697 $ 21,057,222
The change in the investment in unconsolidated affiliates is provided below:
September 30
Cash investment
$ 76,385 $ 18,258
Equity in earnings of unconsolidated affiliate
3,234,632 3,851,871
Distributions from unconsolidated affiliate
(3,644,542 ) -
Change in investment in unconsolidated affiliates
$ (333,525 ) $ 3,870,129
Summary unaudited financial statements of MVP are presented below. Southgate financial statements, which are accounted for under the cost method, are not included:
Income Statements
Years Ended September 30
Revenue
$ 563,535,710 $ 143,052,597
Operating expenses
(290,825,244 ) (78,822,028 )
AFUDC
6,133,873 343,922,690
Other income, net
119,761 9,900,128
Net income
$ 278,964,100 $ 418,053,387
Balance Sheets
September 30
Assets:
Current assets
$ 173,283,635 $ 263,966,727
Construction work in progress
- 1,568,267
Property, plant and equipment, net
9,418,928,665 9,522,815,742
Other assets
1,789,092 13,732,299
Total assets
$ 9,594,001,392 $ 9,802,083,035
Liabilities and Equity:
Current liabilities
$ 40,148,017 $ 168,645,751
Noncurrent liabilities
1,084,072 68,965
Capital
9,552,769,303 9,633,368,319
Total liabilities and equity
$ 9,594,001,392 $ 9,802,083,035
6.
LINE-OF-CREDIT
The Company had been operating with a line-of-credit in the principal amount of $25 million that it renewed annually each March. On March 31, 2025, Roanoke Gas amended its line-of-credit to increase the principal amount to $30 million and extend the maturity date to March 31, 2027. The line-of-credit's variable interest rate is based upon Term SOFR plus 1.25% and provides for multiple-tier borrowing limits to accommodate seasonal borrowing demands. The Company's total borrowing limits during the term of the line-of-credit range from $20 million to $30 million. As of September 30, 2025, the Company had an outstanding balance of $11,916,760 under the line-of-credit.
The Company's total available borrowing limits for the remaining term are as follows:
Available
Line-of-Credit
As of September 30, 2025
$ 20,000,000
October 1, 2025 through March 31, 2026
30,000,000
April 1, 2026 through September 30, 2026
20,000,000
October 1, 2026 through March 31, 2027
30,000,000
A summary of the line-of-credit follows:
September 30
Borrowing limit at year-end
$ 20,000,000 $ 20,000,000
Outstanding balance at year-end
11,916,760 11,166,181
Average rate of interest during year on outstanding balances
5.56 % 6.39 %
Interest rate at year-end
5.42 % 6.29 %
Interest rate on unused line-of-credit
0.25 % 0.15 %
7.
LONG-TERM DEBT
Long-term debt consisted of the following:
September 30
Principal
Unamortized Debt Issuance Costs Principal
Unamortized Debt Issuance Costs
Roanoke Gas:
Unsecured senior note payable at 4.26%, due September 18, 2034
$ 30,500,000 $ 86,887 $ 30,500,000 $ 96,541
Unsecured term note payable at 3.58%, due October 2, 2027
8,000,000 9,632 8,000,000 14,448
Unsecured term note payable at 4.41%, due March 28, 2031
10,000,000 17,229 10,000,000 20,362
Unsecured term note payable at 3.60%, due December 6, 2029
10,000,000 14,971 10,000,000 18,494
Unsecured term note payable at 30-day SOFR plus 1.20%, due August 20, 2026 (swap rate at 2.00%)
15,000,000 - 15,000,000 -
Unsecured term note payable at Term SOFR plus 1.00%, due October 1, 2028 (swap rate at 2.49%)
10,000,000 22,612 10,000,000 27,044
Midstream:
Unsecured term note payable at Term SOFR plus 1.55%, due September 5, 2032 ($14M swap rate at 3.24%, $4M swap rate at 2.443%, and $20.6M swap rate at 5.061%)
38,600,000 171,362 - -
Unsecured term note payable at Term SOFR plus 1.55%, due September 5, 2032 (swap rate at 5.061%)
15,000,000 66,592 - -
Revolving credit facility at Term SOFR plus 1.75%, due September 5, 2030 ("Southgate")
4,215 5,553 - -
Revolving credit facility at Term SOFR plus 1.75%, due September 5, 2030 ("Boost")
- 10,956 - -
Unsecured term note payable at Term SOFR plus 1.55%, retired September 5, 2025
- - 24,855,000 32,299
Unsecured term note payable at Daily Simple SOFR plus 1.26448% (swap rate at 3.24%), retired September 5, 2025
- - 14,000,000 4,213
Unsecured term note payable at Daily Simple SOFR plus 1.26448% (swap rate at 2.443% on designated principal), retired September 5, 2025
- - 6,400,000 21,406
Revolving credit facility at Daily Simple SOFR plus 2.215%, retired September 5, 2025
- - 9,000,000 47,285
Total long-term debt
$ 137,104,215 $ 405,794 $ 137,755,000 $ 282,092
Less: current maturities of long-term debt
(2,846,018 ) - (800,000 ) -
Total long-term debt, net current maturities
$ 134,258,197 $ 405,794 $ 136,955,000 $ 282,092
On September 5, 2025, Midstream established new Term Notes with two banks in the amounts of $38.6 million and $15 million, which refinanced and replaced all of Midstream's outstanding debt. The interest rate on the new Term Notes is one month Term SOFR plus 1.55% with interest payable monthly. The Term Notes also included a 0.3% origination fee and 0.1% annual fee. Quarterly principal payments will be due each October, January, April and July, and repayment terms are based on a schedule aligned with the terms of the MVP shipper agreements, which will expire June 2044. The Term Notes mature on September 5, 2032. Also, on September 5, 2025, Midstream executed two interest rate swap agreements totaling $35.6 million, which corresponds to the term and draw provisions of the Term Note agreement and effectively converts that portion of the variable rate note to a fixed rate instrument with an effective annual interest rate of 5.061%. The two existing interest rate swaps will remain in place, have been redesignated, and when combined with the new interest rate swap agreements, hedged a notional value of $53.6 million.
Additionally, on September 5, 2025, Midstream entered into a Loan Agreement for the MVP Southgate extension and MVP expansion that can be drawn to principal amounts of $1.85 million and $3.65 million, respectively, (the "Notes"). The Notes bear an interest rate of Term SOFR plus 1.75% subject to adjustment to Term SOFR plus 1.55% upon meeting certain milestones. The Notes mature on September 5, 2030, at which time the outstanding principal balance on each note is due. The Loan Agreement included a 0.25% origination fee.
On March 6, 2024, Midstream entered into the Sixth Amendment to Credit Agreement and related Promissory Notes on the non-revolving credit facility. The Sixth Amendment revised the interest rate from Term SOFR plus 2.00% to Term SOFR plus 2.00% subject to adjustment to Term SOFR plus 1.75% and Term SOFR plus 1.55% upon meeting certain milestones. The Sixth Amendment also consolidated the Promissory Notes to one Promissory Note with one lender, increased the available non-revolving credit facility to $25 million, and extended the maturity date to December 31, 2025. All other terms and requirements remain unchanged.
On May 2, 2024, Midstream established a new $9 million line of credit facility. The interest rate on the borrowings under the facility is SOFR plus 2.215%; the arrangement included a 0.40% upfront fee and 0.125% unused line fee. The facility matures on May 2, 2026.
On May 29, 2024, Midstream paid in full the remaining $9 million term note payable that was set to mature June 1, 2024 with proceeds from the new line of credit.
Debt issuance costs are amortized over the life of the related debt. As of September 30, 2025 and 2024, the Company also had an unamortized loss on the early retirement of debt of $1,027,684 and $1,141,872, respectively, which has been deferred as a regulatory asset and is being amortized over a 20-year period.
All of the debt agreements set forth certain representations, warranties and covenants to which the Company is subject, including financial covenants that limit consolidated long-term indebtedness to not more than 65% of total capitalization. All of the debt agreements provide for Priority Indebtedness (defined in the debt agreements) to not exceed 15% of consolidated total assets. The $15 million, $10 million, $53.6 million, $1.85 million and $3.65 million notes have an interest coverage ratio requirement of not less than 1.5 to 1, which excludes the effect of a non-cash impairment on the LLC investments up to the total investment as of December 31, 2021. The Company was in compliance with all debt covenants as of September 30, 2025 and 2024.
The aggregate annual maturities of long-term debt for the next five years ending after September 30, 2025 are as follows:
Year Ending September 30
Maturities
$ 17,846,018
2,846,018
10,846,017
12,846,018
12,850,233
Thereafter
79,869,911
Total
$ 137,104,215
Roanoke Gas has a term note in the principal amount of $15 million maturing in August 2026. The Company has a positive record of refinancing term notes, as well as has access to sufficient financing resources, including availability under the line-of-credit, to meet the payment requirements associated with this term note. Thus the Company has presented this balance within notes payable of long-term debt on the consolidated balance sheets as of September 30, 2025.
8.
FAIR VALUE
The following table summarizes the Company’s financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements by level within the fair value hierarchy as defined in Note 1 as of September 30, 2025 and 2024, respectively. There have been no changes to the Company's valuation techniques during fiscal years ended September 30, 2025 and 2024.
Fair Value Measurements - September 30, 2025
Quoted Prices in Active Markets Significant Other Observable Inputs Significant Unobservable Inputs
Fair Value
Level 1
Level 2
Level 3
Assets:
Interest rate swaps - current
$ 828,573 $ - $ 828,573 $ -
Interest rate swaps - noncurrent
$ 421,511 - $ 421,511
Total
$ 1,250,084 $ - $ 1,250,084 $ -
Liabilities:
Natural gas purchases
$ 135,863 $ - $ 135,863 $ -
Interest rate swaps - current
$ 57,144 $ - $ 57,144 $ -
Interest rate swaps - noncurrent
$ 298,016 $ - $ 298,016 $ -
Total
$ 491,023 $ - $ 491,023 $ -
Fair Value Measurements - September 30, 2024
Quoted Prices in Active Markets
Significant Other Observable Inputs
Significant Unobservable Inputs
Fair Value
Level 1
Level 2
Level 3
Assets:
Interest rate swaps - current
$ 871,026 $ - $ 871,026 $ -
Interest rate swaps - noncurrent
$ 1,191,526 $ - $ 1,191,526 $ -
Total
$ 2,062,552 $ - $ 2,062,552 $ -
Liabilities:
Natural gas purchases
$ 761,020 $ - $ 761,020 $ -
Total
$ 761,020 $ - $ 761,020 $ -
The fair value of the interest rate swaps is determined by using the counterparty's proprietary models that include observable quoted market interest rates and interest rate futures as well as certain assumptions regarding past, present and future market conditions.
See Note 5 for discussion on the fair value assumptions of the Company's investment in the LLC.
Under the asset management contract, a timing difference can exist between the payment for natural gas purchases and the actual receipt of such purchases. Payments are made based on a predetermined monthly volume with the price based on the weighted average first of the month index prices corresponding to the month of the scheduled payment. At September 30, 2025 and 2024, the Company had recorded in accounts payable the estimated fair value of the liability based on the corresponding first of month quoted index prices for which the liability was expected to be settled.
The Company’s non-financial assets and liabilities that are measured at fair value on a nonrecurring basis consist of its AROs. The AROs are measured at fair value at initial recognition based on expected future cash flows to settle the obligation.
The carrying value of cash and cash equivalents, accounts receivable, borrowings under line-of-credit, accounts payable, customer credit balances and customer deposits is a reasonable estimate of fair value due to the short-term nature of these financial instruments. In addition, the carrying amount of the variable rate line-of-credit is a reasonable approximation of its fair value. The following table summarizes the fair value of the Company’s financial assets and liabilities that are not adjusted to fair value in the consolidated financial statements as of September 30, 2025 and 2024.
Fair Value Measurements - September 30, 2025
Carrying
Quoted Prices in Active Markets Significant Other Observable Inputs Significant Unobservable Inputs
Amount
Level 1
Level 2
Level 3
Liabilities:
Current maturities of long-term debt
$ 2,846,018 $ - $ - $ 2,846,018
Notes payable
134,258,197 - - 131,605,756
Total
$ 137,104,215 $ - $ - $ 134,451,774
Fair Value Measurements - September 30, 2024
Carrying
Quoted Prices in Active Markets Significant Other Observable Inputs Significant Unobservable Inputs
Amount
Level 1
Level 2
Level 3
Liabilities:
Current maturities of long-term debt
$ 800,000 $ - $ - $ 800,000
Notes payable
136,955,000 - - 135,471,275
Total
$ 137,755,000 $ - $ - $ 136,271,275
The fair value of long-term debt is estimated by discounting the future cash flows of the fixed rate debt based on the underlying Treasury rate or other Treasury instrument with a corresponding maturity period and estimated credit spread extrapolated based on market conditions since the issuance of the debt.
ASC 825, Financial Instruments, requires disclosures regarding concentrations of credit risk from financial instruments. Cash equivalents are investments in high-grade, short-term securities (original maturity less than three months), placed with financially sound institutions. Accounts receivable are from a diverse group of customers including individuals and small and large companies in various industries. The Company maintains certain credit standards with its customers and requires a customer deposit if such evaluation warrants.
9.
INCOME TAXES
Under the provisions of ASC 740, the deferred tax assets and liabilities of the Company were revalued in fiscal 2018 to reflect the reduction in the corporate federal income tax rate. As a result of the revaluation, the excess deferred income taxes of the regulated operations of Roanoke Gas were reclassified to a regulatory liability. The excess deferred taxes related to the depreciable property are being returned to customers over the remaining weighted average useful life of the property with a corresponding reduction in income tax expense. The excess deferred taxes related to the other regulatory basis differences were being collected from customers over a five-year period, which concluded in December 2023.
The details of income tax expense (benefit) are as follows:
Years Ended September 30
Current income taxes:
Federal
$ 3,167,466 $ 3,128,721
State
733,266 689,671
Total current income taxes
3,900,732 3,818,392
Deferred income taxes:
Federal
(156,415 ) (398,588 )
State
347,218 276,807
Total deferred income taxes
190,803 (121,781 )
Total income tax expense
$ 4,091,535 $ 3,696,611
Income tax expense for the years ended September 30, 2025 and 2024 differed from amounts computed by applying the U.S. federal income tax rate to earnings before income taxes due to the following:
Years Ended September 30
Income before income taxes
$ 17,371,505 $ 15,457,507
Corporate federal income tax rate
21 % 21 %
Income tax expense computed at the federal statutory rate
$ 3,648,016 $ 3,246,076
State income taxes, net of federal income tax expense
853,582 763,518
Net amortization of excess deferred taxes on regulated operations
(366,844 ) (315,708 )
Net amortization of RNG tax credits
(100,649 ) (100,649 )
Reserve for unrecognized tax benefits
- 82,000
Other, net
57,430 21,374
Total income tax expense
$ 4,091,535 $ 3,696,611
During fiscal 2021, the Company engaged an outside firm to conduct a study of its activities that would qualify for the Research and Development ("R&D") credit under 26 U.S. Code § 41 - Credit for increasing research activities. Upon completion of this study, the Company filed amended federal income tax returns for the 2017, 2018 and 2019 fiscal years to claim the R&D tax credit. The Company also filed for the R&D tax credit on its fiscal 2020 federal income tax return. A second study was performed during fiscal 2022, and the Company filed for the R&D tax credit on its fiscal 2021 federal income tax return. During fiscal 2021 and 2022, the Company also applied for a Virginia State tax credit related to the R&D study.
Amounts corresponding with the tax credits were deferred as a regulatory liability as such benefits will be returned to customers through future rate adjustments. These credits were originally being amortized over the 20-year tax-life of the related utility plant. In accordance with the SCC settlement agreement in relation to the Company’s non-gas rate application, the amortization of the R&D tax credit was halted effective August 1, 2023 as the IRS began an examination on the fiscal 2018 and 2019 federal tax returns. As such, no amortization was recognized associated with the R&D tax credits in fiscal 2025 and 2024.
During September 2025, the Company participated in the IRS Fast Track Settlement (FTS), which is a process that provides the IRS and taxpayers an opportunity to resolve disputes with an appeals official using mediation skills and settlement authority. The IRS and Company agreed on a settlement equal to 40% of the R&D tax credits claimed for fiscal 2018 and 2019, the two years under examination. Once the IRS finalizes the resolution and the refunds are received, the Company will proceed with refunding the R&D tax credits, net of related fees, to customers over a 12-month period through a mechanism to be approved by the SCC. The net credit amount deferred as a regulatory liability as of September 30, 2025 was $2,568,143, which reflects adjustments to 40% of the fiscal 2018 and 2019 credits claimed and the remaining balance of the fiscal 2020 and 2021 credits claimed. As part of the settlement, the Company grossed up the tax credit consistent with treatment of the excess deferred taxes. The deferred tax asset associated with the R&D tax credits was adjusted to $705,848 as of September 30, 2025 to reflect the adjustment for fiscal 2018 and 2019.
During fiscal 2023, the Company engaged an outside firm to conduct a study of its RNG facility to determine eligibility for the Federal Energy Investment Tax Credit under 26 U.S. Code § 48 - Energy credit (“RNG tax credit”). Upon completion of the study, the Company determined a credit in the amount of $1,892,164 to be claimed on the fiscal 2023 tax return. Similar to the treatment of the R&D tax credits, the Company deferred the RNG tax credit as a regulatory liability, which is being amortized over the 20-year tax-life of the related asset. Further, as part of the SCC order approving the RNG project and corresponding rates charged to customers, any tax credits attributable to the RNG project are to be used to reduce the cost to customers through the RNG Rider. Accordingly, the Company grossed up the RNG tax credit consistent with treatment of the excess deferred taxes, thereby creating a deferred tax asset of $655,862, which is also being amortized over the 20-year tax-life of the related asset. The Company recognized $127,404 of amortization as part of income tax expense on the consolidated statements of income in both fiscal 2025 and 2024 related to the federal RNG tax credit.
The tax effects of temporary differences that give rise to the deferred tax assets and deferred tax liabilities are as follows:
September 30
Deferred tax assets:
Accrued pension and postretirement medical benefits
$ 556,316 $ 512,778
Regulatory effect of change in federal income tax rate
2,433,559 2,553,086
Cost of gas held in storage
773,167 835,094
Deferred compensation
1,382,130 1,166,850
Impairment of unconsolidated affiliate
13,722,837 14,077,357
Regulatory effect on tax credits
1,277,006 1,437,670
Other
861,076 641,300
Total gross deferred tax assets
21,006,091 21,224,135
Deferred tax liabilities:
Utility property
20,367,400 19,879,747
MVP investment
2,054,156 1,586,837
Interest rate swaps
230,356 530,903
Accrued gas cost
14,339 345,464
Total gross deferred tax liabilities
22,666,251 22,342,951
Net deferred tax asset
617,390 771,746
Net deferred tax liability
$ 2,277,550 $ 1,890,562
Deferred tax assets and liabilities are recorded on the consolidated balance sheets on a net basis by taxing jurisdictions. As of September 30, 2025 and 2024, the Company's consolidated balance sheets included net deferred tax liabilities of $2,277,550 and $1,890,562, respectively, in deferred credits and other non-current liabilities and net deferred tax assets of $617,390 and $771,746, respectively, in other non-current assets.
ASC 740 provides for the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recognized in the financial statements. The Company evaluated its tax positions and recorded a reserve for unrecognized tax benefits of $273,936 as of September 30, 2024. These unrecognized tax benefits relate to tax positions taken in the Company's prior tax returns. The reduction to $0 in the current year is due to the adjustments made to the Company's income tax assets and liabilities as a result of the FTS previously discussed. A reconciliation of the Company's unrecognized tax benefits is as follows:
September 30
Beginning balance
$ 273,936 $ -
Increase (decrease) resulting from prior period tax positions
(273,936 ) 273,936
Ending Balance
$ - $ 273,936
The Company’s policy is to classify interest associated with uncertain tax positions as interest expense in the financial statements. Tax penalties, if any, are netted against other income.
The Company files a consolidated federal income tax return and state income tax returns in Virginia and West Virginia, and thus subject to examinations by federal and state tax authorities. The Company adjusted its income tax assets and liabilities to reflect the outcome of the FTS as of September 30, 2025. Due to the federal government shutdown in October and November 2025, the Company has not received final notice from the IRS officially closing the Company's federal returns for fiscal 2018 and 2019. Once final notice is received, the federal returns and the state returns for Virginia and West Virginia for the tax years ended through September 30, 2022 are closed to examination.
10.
COMMON STOCK OPTIONS
The KEYSOP provides for the issuance of common stock options to officers and certain other full-time salaried employees to acquire shares of the Company’s common stock. As of September 30, 2025, the number of shares available for future grants was 16,000.
ASC 718, Compensation-Stock Compensation, requires that compensation expense be recognized for the issuance of equity instruments to employees. No options were granted during the fiscal year ended September 30, 2025. During the fiscal year ended September 30, 2024, the Board approved stock option grants to certain officers. As required by the KEYSOP, each option's exercise price per share equaled the fair value of the Company's common stock on the grant date. Pursuant to the plan, the options vest over a six-month period and are exercisable over a ten-year period from the date of issuance.
As the Company's stock options are not traded on the open market, the fair value of each grant is estimated on the date of grant using the Black-Scholes option pricing model including the following assumptions:
Years Ended September 30
Expected volatility
N/A 32.07 %
Expected dividends
N/A 2.84 %
Expected exercise term (years)
N/A 7
Risk-free interest rate
N/A 4.95 %
The underlying methods regarding each assumption are as follows:
Expected volatility is based on the historical volatility of the daily closing price of the Company's common stock.
Expected dividend rate is based on historical dividend payout trends.
Expected exercise term is based on the average time historical option grants were outstanding before being exercised.
Risk-free interest rate is based on the 7-year Treasury rate on the date of option grant.
Forfeitures are recognized when they occur.
Stock option transactions under the Company's plans are summarized below.
Number of Shares
Weighted- Average Exercise Price
Weighted- Average Remaining Contractual Terms (years)
Aggregate Intrinsic Value1
Options outstanding, September 30, 2023
22,000 $ 20.23 5.6 $ 18,388
Options granted
10,000 16.62
Options forfeited
(4,000 ) 19.90
Options outstanding, September 30, 2024
28,000 $ 18.98 5.8 $ 127,988
Options granted
-
Options exercised
-
Options outstanding, September 30, 2025
28,000 $ 18.98 4.8 $ 125,388
Vested and exercisable at September 30, 2025
28,000 $ 18.98 4.8 $ 125,388
(1) Aggregate intrinsic value includes only those options where the exercise price is below the market price.
Years Ended September 30
Weighted-average grant date option fair value
$ - $ 5.15
Stock-based compensation
- 51,500
Intrinsic value of options exercised
- -
Proceeds from exercise of stock options
- -
Stock-based compensation related to stock options disclosed in the table above is included within operations and maintenance expense on the consolidated statements of income.
11.
OTHER STOCK PLANS
Dividend Reinvestment and Stock Purchase Plan
The Company offers a DRIP plan to shareholders of record for the reinvestment of dividends and the opportunity to purchase of up to $100,000 per year in additional shares of common stock of the Company. Under the DRIP, the Company issued 30,027 and 33,226 shares in 2025 and 2024, respectively.
After taking into account the activity discussed above and dividends reinvested, as of September 30, 2025, the Company had 202,371 shares of stock available for issuance under the DRIP.
Restricted Stock Plan for Outside Directors
The Board of Directors of the Company implemented the RSPD in 1997. Under the RSPD, each director may elect annually to have up to 100% of his or her fees paid in shares of common stock ("Director Restricted Stock"); however, a minimum of 40% of the monthly retainer fee must be paid to each non-employee director of Resources in shares of Director Restricted Stock until such time as the director has accumulated at least 10,000 shares. The number of shares of Director Restricted Stock awarded each month is determined based on the closing sales price of Resources' common stock on the Nasdaq Global Market on the first business day of the month. The Director Restricted Stock issued under the Plan vests only in the case of a participant's death, disability, retirement, or in the event of a change in control of Resources. The Director Restricted Stock may not be sold, transferred, assigned or pledged by the participant until the shares have vested under the terms of the Plan. The shares of Director Restricted Stock will be forfeited to Resources by a participant's voluntary resignation during his or her term on the Board or removal for cause as a director.
The Company assumes all directors will complete their term and there will be no forfeiture of the Director Restricted Stock. Since the inception of the RSPD, no director has forfeited any shares of Director Restricted Stock. The Company recognizes the market value of the Director Restricted Stock as compensation in the period it is issued.
The following table reflects the director compensation activity pursuant to the Plan:
Shares
Weighted-Average Fair Value on Date of Grant
Shares
Weighted-Average Fair Value on Date of Grant
Beginning of year balance
137,764 $ 17.11 122,207 $ 16.84
Granted
15,898 20.82 15,557 19.23
End of year balance
153,662 $ 17.49 137,764 $ 17.11
The fair market value of the Director Restricted Stock included as compensation during fiscal years ended September 30, 2025 and 2024 was $331,030 and $299,200, respectively, and included within operations and maintenance expense on the consolidated statements of income. No Director Restricted Stock was forfeited during fiscal years ended September 30, 2025 or 2024.
After taking into account the activity discussed above and dividends reinvested, as of September 30, 2025, the Company had 149,022 shares available for issuance under the RSPD.
RGC Resources, Inc. Restricted Stock Plan
The Board of Directors of the Company implemented the RSPO in 2017 as approved by shareholders. Under the RSPO, the Compensation Committee of the Board of Directors may grant shares of common stock ("Officer Restricted Stock") that vest over time to key employees and officers for the purpose of attracting and retaining those individuals essential to the operation and growth of the Company. The RSPO provides for certain restrictions and non-transferability requirements until minimum levels of ownership are obtained. Such restrictions may continue beyond the vesting period.
The Company assumes all officers will complete their requirements and there will be no forfeiture of the Officer Restricted Stock.
The following table reflects the officer compensation activity pursuant to the RSPO:
Shares
Weighted-Average Fair Value on Date of Grant
Shares
Weighted-Average Fair Value on Date of Grant
Beginning of year balance
31,482 $ 20.09 8,966 $ 23.19
Granted
30,470 20.00 45,723 20.12
Vested
(26,736 ) 20.08 (23,207 ) 21.35
End of year balance
35,216 $ 20.02 31,482 $ 20.09
The fair market value of the Officer Restricted Stock included as compensation during fiscal years ended September 30, 2025 and 2024 was $673,057 and $660,424, respectively, and included within operations and maintenance expense on the consolidated statements of income. As of September 30, 2025 and 2024, there was $222,026 and $285,683, respectively, of unamortized compensation expense related to unvested Officer Restricted Stock. No Officer Restricted Stock was forfeited during fiscal years ended September 30, 2025 or 2024.
After taking into account the activity discussed above and dividends reinvested, as of September 30, 2025, the Company had 286,560 shares available for issuance under the RSPO.
Stock Bonus Plan
Shares from the Stock Bonus Plan may be issued to certain employees and management personnel in recognition of their performance and service. Under the Stock Bonus Plan, the Company issued 1,352 and 1,562 valued at $27,500 and $24,841, respectively, during the fiscal years ended September 30, 2025 and 2024.
As of September 30, 2025, the Company had 1,766 shares of stock available for issuance under the Stock Bonus Plan.
12.
EMPLOYEE BENEFIT PLANS
The Company sponsors both a noncontributory pension plan and a postretirement plan. The pension plan covers all employees hired prior to January 2017 and benefits fully vest after 5 years of credited service. Benefits paid to retirees are based on age at retirement, years of service and average compensation. Effective January 1, 2017, a "soft freeze" to the pension plan was implemented, and employees hired on or after that date are no longer eligible to participate. Commensurate with the "soft freeze" in the pension plan, the Company amended its 401(k) Plan, allowing management to authorize a discretionary contribution to the 401(k) account for those employees hired on or after January 1, 2017. The amount, if any, of this discretionary contribution would be determined each year and would be applied to the eligible employees in the following calendar year. This Company contribution would be in addition to any employee elected deferrals and employer match as provided for under the 401(k) Plan.
The postretirement plan provides certain health care, supplemental retirement and life insurance benefits to retired employees who meet specific age and service requirements. Employees hired prior to January 1, 2000 are eligible to participate in the postretirement plan. Employees must have a minimum of 10 years of service and retire after attaining the age of 55 in order to vest in the postretirement plan. Retiree contributions to the plan are based on the number of years of service to the Company as determined under the pension plan.
Employers who sponsor defined benefit plans must recognize the funded status of defined benefit pension and other postretirement plans as an asset or liability in their statements of financial position and recognize changes in that funded status in the year in which the changes occur through comprehensive income. For pension plans, the benefit obligation is the projected benefit obligation, and for other postretirement plans, the benefit obligation is the accumulated benefit obligation. The Company established a regulatory asset for the portion of the obligation expected to be recovered through rates in future periods. The regulatory asset is adjusted for the recognition of actuarial gains and losses. The portion of the obligation attributable to the unregulated operations of the holding company is recognized in other comprehensive income, with actuarial gains and losses recognized using the corridor method.
The following table sets forth the benefit obligation, fair value of plan assets, the funded status of the plans, and amounts recognized in the Company’s consolidated financial statements:
Pension Plan
Postretirement Plan
Accumulated benefit obligation
$ 26,298,490 $ 26,859,162 $ 10,462,318 $ 10,842,455
Change in benefit obligation:
Benefit obligation at beginning of year
$ 29,873,428 $ 26,747,624 $ 10,842,455 $ 11,248,448
Service cost
387,429 324,265 4,376 30,398
Interest cost
1,410,406 1,468,822 507,423 613,477
Actuarial loss (gain)
(752,215 ) 2,613,621 (297,327 ) (540,914 )
Benefit payments, net of retiree contributions
(1,439,028 ) (1,280,904 ) (594,609 ) (508,954 )
Benefit obligation at end of year
$ 29,480,020 $ 29,873,428 $ 10,462,318 $ 10,842,455
Change in fair value of plan assets:
Fair value of plan assets at beginning of year
$ 31,054,138 $ 26,878,661 $ 15,078,281 $ 13,019,313
Actual return on plan assets, net of taxes
872,291 5,456,381 907,150 2,567,922
Employer contributions
- - - -
Benefit payments, net of retiree contributions
(1,439,028 ) (1,280,904 ) (594,609 ) (508,954 )
Fair value of plan assets at end of year
$ 30,487,401 $ 31,054,138 $ 15,390,822 $ 15,078,281
Funded status
$ 1,007,381 $ 1,180,710 $ 4,928,504 $ 4,235,826
Amounts recognized in the consolidated balance sheet consist of:
Benefit plan assets under other non-current assets
$ 1,007,381 $ 1,180,710 $ 4,928,504 $ 4,235,826
Amounts recognized in accumulated other comprehensive income:
Net actuarial loss (gain), net of tax
$ 923,823 $ 432,149 $ (520,987 ) $ (227,071 )
Total amounts included in accumulated other comprehensive income, net of tax
$ 923,823 $ 432,149 $ (520,987 ) $ (227,071 )
Amounts deferred to a regulatory asset (liability):
Net actuarial loss (gain)
$ 2,199,542 $ 3,041,666 $ (3,879,294 ) $ (4,032,929 )
Amounts recognized as regulatory assets (liabilities)
$ 2,199,542 $ 3,041,666 $ (3,879,294 ) $ (4,032,929 )
The Company expects that approximately $31,000, before tax, of AOCI will be recognized in net periodic benefit costs in fiscal 2026 and approximately $31,000 of amounts deferred as regulatory assets and approximately $158,000 of amounts deferred as regulatory liabilities will be amortized and recognized in net periodic benefit costs in fiscal 2026.
The following table details the actuarial assumptions used in determining the projected benefit obligations and net benefit cost of the pension plan and the accumulated benefit obligations and net benefit cost of the postretirement plan:
Pension Plan
Postretirement Plan
Assumptions used to determine benefit obligations:
Discount rate
5.29 % 4.83 % 5.16 % 4.83 %
Expected rate of compensation increase
4.00 % 4.00 % N/A N/A
Assumptions used to determine benefit costs:
Discount rate
4.83 % 5.63 % 4.83 % 5.63 %
Expected long-term rate of return on plan assets
4.95 % 4.50 % 4.95 % 4.21 %
Expected rate of compensation increase
4.00 % 4.00 % N/A N/A
To develop the expected long-term rate of return on plan assets assumption, the Company, with input from the Plans' actuaries and investment advisors, considered the historical returns and the future expectations for returns for each asset class, as well as the target asset allocation of each plan’s portfolio.
Components of net periodic benefit cost are as follows:
Pension Plan
Postretirement Plan
Service cost
$ 387,429 $ 324,265 $ 4,376 $ 30,398
Interest cost
1,410,406 1,468,822 507,423 613,477
Expected return on plan assets
(1,503,902 ) (1,179,830 ) (729,708 ) (533,249 )
Recognized loss (gain)
59,423 316,522 (232,611 ) (40,597 )
Net periodic benefit cost (income)
$ 353,356 $ 929,779 $ (450,520 ) $ 70,029
Service cost is included in operations and maintenance expense in the consolidated statements of income. All other components of net periodic benefit costs are included in other income, net in the consolidated statements of income.
The assumed health care cost trend rates used in measuring the accumulated benefit obligation for the postretirement plan are presented below:
Pre 65
Post 65
Health care cost trend rate assumed for next year
7.00 % 7.00 % 5.60 % 5.60 %
Rate to which the cost trend is assumed to decline (the ultimate trend rate)
4.00 % 4.00 % 4.00 % 4.00 %
Year that the rate reaches the ultimate trend rate
The health care cost trend rate assumptions could have a significant effect on the amounts reported. A change of 1% would have the following effects:
1% Increase
1% Decrease
Effect on total service and interest cost components
$ 58,000 $ (50,000 )
Effect on accumulated postretirement benefit obligation
1,113,000 (955,000 )
The primary objectives of both plans' investment policies are to maintain investment portfolios that diversify risk through prudent asset allocation parameters, achieve asset returns that meet or exceed the corresponding actuarial assumptions and will provide for future benefits. The Company's pension plan allocation approach seeks to match the duration of the fixed income portion of the portfolio with the duration of the plan's liabilities. Such allocation is designed to reduce the overall volatility in the pension plan relative to the funded status. The equity allocations in both plans provide for potential returns to offset growth in the corresponding liabilities.
Based on its most recent evaluation of returns for the asset classes within each plan's investment portfolio, the Company set the expected long-term rate of return for both the pension plan and the postretirement plan for fiscal 2026 at 5.75%.
The Company’s ultimate target and actual asset allocation in the pension and postretirement plans as of September 30, 2025 and 2024 were:
Pension Plan
Postretirement Plan
Target
Target
Asset category:
Equity securities
25 % 23 % 25 % 30 % 38 % 48 %
Debt securities
75 % 77 % 75 % 70 % 53 % 36 %
Cash
- % - % - % - % 9 % 16 %
The Company uses the fair value hierarchy described in Note 1 to classify these assets. The mutual funds are included under Level 1 in the fair value hierarchy as their fair values are based on quoted net asset values of the shares held in the investments in the plans. The bond funds and certain other investments are included under Level 2 as these investments have observable Level 2 pricing inputs, including quoted prices for similar assets in active or non-active markets. While the underlying asset values are quoted prices, the net asset value of a unit in these funds is not publicly quoted. The following tables contain the fair value classifications of the plans' assets:
Pension Plan
Fair Value Measurements - September 30, 2025
Fair Value
Level 1
Level 2
Level 3
Asset Class:
Cash
$ 27,603 $ 27,603 $ - $ -
Common and Collective Trust and Pooled Funds:
Bond Funds
19,460,378 - 19,460,378 -
Mutual Funds:
Domestic Fixed Income
3,901,202 3,901,202 - -
Equities
Domestic Large Cap Growth
2,161,688 2,161,688 - -
Domestic Large Cap Value
2,470,055 2,470,055 - -
Domestic Small/Mid Cap Core
1,023,627 1,023,627 - -
Foreign Large Cap Growth
442,847 442,847 - -
Foreign Large Cap Value
469,821 469,821 - -
Foreign Large Cap Core
530,180 530,180 - -
Total
$ 30,487,401 $ 11,027,023 $ 19,460,378 $ -
Pension Plan
Fair Value Measurements - September 30, 2024
Fair Value
Level 1
Level 2
Level 3
Asset Class:
Cash
$ 142,921 $ 142,921 $ - $ -
Common and Collective Trust and Pooled Funds:
Bond Funds
19,505,237 - 19,505,237 -
Mutual Funds:
Domestic Fixed Income
3,791,697 3,791,697 - -
Equities
Domestic Large Cap Growth
2,073,092 2,073,092 - -
Domestic Large Cap Value
2,469,045 2,469,045 - -
Domestic Small/Mid Cap Core
1,297,579 1,297,579 - -
Foreign Large Cap Growth
498,732 498,732 - -
Foreign Large Cap Value
482,222 482,222 - -
Foreign Large Cap Core
793,613 793,613 - -
Total
$ 31,054,138 $ 11,548,901 $ 19,505,237 $ -
Postretirement Plan
Fair Value Measurements - September 30, 2025
Fair Value
Level 1
Level 2
Level 3
Asset Class:
Cash
$ 1,462,600 $ 1,462,600 $ - $ -
Mutual Funds:
Bonds
Domestic Fixed Income
8,089,514 8,089,514 - -
Equities
Domestic Large Cap Growth
1,340,584 1,340,584 - -
Domestic Large Cap Value
2,799,537 2,799,537 - -
Domestic Small/Mid Cap Core
453,828 453,828 - -
Foreign Large Cap Growth
217,707 217,707 - -
Foreign Large Cap Core
1,027,052 1,027,052 - -
Total
$ 15,390,822 $ 15,390,822 $ - $ -
Postretirement Plan
Fair Value Measurements - September 30, 2024
Fair Value
Level 1
Level 2
Level 3
Asset Class:
Cash
$ 2,381,909 $ 2,381,909 $ - $ -
Mutual Funds:
Bonds
Domestic Fixed Income
5,457,976 5,457,976 - -
Equities
Domestic Large Cap Growth
2,412,824 2,412,824 - -
Domestic Large Cap Value
1,996,262 1,996,262 - -
Domestic Small/Mid Cap Core
738,393 738,393 - -
Foreign Large Cap Growth
532,391 532,391 - -
Foreign Large Cap Value
652,023 652,023 - -
Foreign Large Cap Core
906,503 906,503 - -
Total
$ 15,078,281 $ 15,078,281 $ - $ -
Each mutual fund or common collective trust fund has been categorized based on its primary investment strategy.
Annual funding contributions to the pension plan and postretirement plan are made under advisement from the Company's actuaries and investment advisor based upon ERISA funding requirements. For the years ended September 30, 2025 and 2024, no contributions were made to the pension plan or postretirement plan. At this time, the Company does not anticipate making any funding contributions to the pension plan or postretirement plan in fiscal 2026.
The following table reflects expected future benefit payments:
Pension
Postretirement
Fiscal year ending September 30
Plan
Plan
$ 1,463,000 $ 728,140
1,560,000 753,633
1,630,000 747,643
1,701,000 773,121
1,780,000 760,210
2031 - 2035 9,733,000 3,794,802
The NQDC Plan is an unfunded, nonqualified benefit plan offered to select members of senior management not eligible to participate in the pension plan. The NQDC Plan also contains a long-term retention element for certain members of senior management. Under the NQDC Plan, participants have the right to defer a percentage of base salary as well as receive discretionary credits from the Company. The Company's discretionary credits vest over time. Any benefits distributed from the NQDC Plan are paid from the general assets of the Company. As the plan is unfunded, the balance reflected in the table below is a noncurrent liability included in benefit plan liabilities on the consolidated balance sheet.
Beginning deferred compensation balance
$ 113,600 $ 47,674
Employer contributions
80,510 52,400
Earnings
7,084 13,526
Ending deferred compensation balance
$ 201,194 $ 113,600
The Company sponsors a 401(k) Plan covering all eligible employees who elect to participate. Employees may contribute from 1% to 50% of their annual compensation to the 401(k) Plan, either on a pre-tax or post-tax basis, limited to a maximum annual amount as set periodically by the IRS. The Company matches 100% of the participant’s first 4% of contributions and 50% of the next 2% of contributions. The 401(k) Plan also provides for discretionary contributions for employees hired on or after January 1, 2017. The following table reflects the Company's contributions:
Years Ended September 30
Matching contribution
$ 466,630 $ 427,022
Discretionary contribution
137,114 112,207
13.
LEASES
During 2023, the Company entered into a land lease in conjunction with its RNG facility that has a 20-year term with two five-year Company renewal options that are not considered part of the ROU asset and liability as it was not reasonably certain that the Company would exercise these options. The Company also has two other operating leases with original terms ranging from 3 to 6 years, one of which was renewed during fiscal 2025. The operating lease ROU assets of $341,612 are reflected in other non-current assets in the consolidated balance sheets. The current operating lease liabilities of $25,600 and non-current lease liabilities of $319,573 are included in other current liabilities and deferred credits and other non-current liabilities, respectively, in the consolidated balance sheets. The cost components of the Company’s operating leases are included under operations and maintenance expense in the consolidated statements of income and were less than $50,000 for each period presented.
Other information related to leases were as follows:
Supplemental Cash Flow Information:
Cash paid on operating leases
$ 42,900 $ 37,900
Right of use obtained in exchange for operating lease obligations
36,734 N/A
Weighted-average remaining term (in years)
15.7 17.4
Weighted-average discount rate
5.64 % 5.65 %
On September 30, 2025, the future minimum rental payments under non-cancelable operating leases were as follows:
$ 51,268
43,238
39,600
26,400
26,400
Thereafter
316,800
Total minimum lease payments
503,706
Less imputed interest
(158,533 )
Total
$ 345,173
14.
COMMITMENTS AND CONTINGENCIES
Long-Term Contracts
Due to the nature of the natural gas distribution business, Roanoke Gas enters into agreements with suppliers and pipelines to contract for natural gas commodity purchases, storage capacity and pipeline delivery capacity. Roanoke Gas obtains most of its natural gas supply through third-party asset management contracts. Through March 31, 2025, the Company utilized two asset managers to optimize the use of its transportation, storage rights and gas supply inventories, which helps to ensure a secure and reliable source of natural gas. Those services were consolidated to one asset manager as of April 1, 2025. Under the current asset management contract, Roanoke Gas has designated the asset manager to act as agent for its storage capacity and all gas balances in storage. Roanoke Gas retains ownership of gas in storage. Under provisions of this contract, Roanoke Gas is obligated to purchase its winter storage requirements from the asset manager during the spring and summer injection periods at market price. The current asset management contract was signed for a three year period which will expire in March 2028. The volumetric obligation as of September 30, 2025 for the remainder of the contract period is 2,071,061 DTH for fiscal years 2026 and 2027 and 295,721 DTH for fiscal year 2028.
In addition to the volumetric commitment, the Company also has fixed price agreements to purchase approximately 1.36 million DTH, from October 2025 to March 2026, at prices ranging from $2.92 to $4.13 per DTH.
Roanoke Gas also has contracts for pipeline and storage capacity which extend for various periods. These capacity costs and related fees are valued at tariff rates in place as of September 30, 2025. These rates may increase in the future based upon rate filings and rate orders granting a rate change to the pipeline or storage operator. Subsequent to year end, one contract price increased materially effective November 1, 2025, as a result of the supplier filing a rate case; however, this rate has not yet been finalized. Roanoke Gas expended approximately $40,843,000 and $30,880,000 under the asset management, pipeline and storage contracts in fiscal years 2025 and 2024, respectively, including approximately $4,180,000 and $1,048,000 in fiscal years 2025 and 2024, respectively, related to the MVP in which the Company has an investment. The table below details the pipeline and storage capacity commitments as of September 30, 2025 for the remainder of the contract period.
Pipeline and
Year
Storage Capacity
2025 - 2026
$ 21,214,051
2026 - 2027
19,808,347
2027 - 2028
16,077,977
2028 - 2029
13,930,198
2029 - 2030
9,276,138
Thereafter
57,469,500
Total
$ 137,776,211
Roanoke Gas maintains franchise agreements granted by the local cities and towns served by the Company. Roanoke Gas renewed its franchise agreements with the City of Roanoke, the City of Salem and the Town of Vinton in 2016 for 20-year terms to expire in December 2035. Per these agreements, franchise fees increase at a rate of 3% annually. As of September 30, 2025, $1,690,215 in future obligations remain under the franchise agreements.
Other Contracts
The Company maintains other agreements in the ordinary course of business covering various maintenance, equipment, user fees and service contracts. These agreements currently extend through December 2031 and are not material to the Company.
Environmental Matters
Roanoke Gas operated an MGP as a source of fuel for lighting and heating until the early 1950’s. A by-product of operating the MGP was coal tar, and the potential exists for tar waste contaminants at the former plant site. While the Company does not currently recognize any commitments or contingencies related to environmental costs, should the Company ever be required to remediate the site, it will pursue all prudent and reasonable means to recover any related costs, including the use of insurance claims and regulatory approval for rate case recognition of expenses associated with any work required.
15.
SUBSEQUENT EVENTS
The Company has evaluated subsequent events through the date the financial statements were issued. There were no other items not otherwise disclosed which would have materially impacted the Company’s consolidated financial statements.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures.
Disclosure Controls and Procedures
The Company maintains disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) that are designed to be effective in providing reasonable assurance that information required to be disclosed in reports under the Exchange Act are identified, recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to management to allow for timely decisions regarding required disclosure.
As of September 30, 2025, the Company completed an evaluation, under the supervision and with the participation of management, including the chief executive officer and the chief financial officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures. Based upon that evaluation, the chief executive officer and chief financial officer concluded that the Company’s disclosure controls and procedures were effective at the reasonable assurance level as of September 30, 2025.
Changes in Internal Control over Financial Reporting
On April 1, 2025, the Company implemented a new enterprise resource planning (“ERP”) system, which replaced the existing ERP system, to improve the efficiency of certain financial and related transactional processes; this system did not replace the system of record for revenue transactions with customers. In connection with this implementation, the Company has enhanced its processes and procedures, which has resulted in changes to internal control over financial reporting, to align with the upgraded system functionality. The Company will continue to monitor and evaluate the operating effectiveness of the related controls during subsequent periods.
Management routinely reviews the Company’s internal control over financial reporting and makes changes, as necessary, to enhance the effectiveness of the internal controls over financial reporting. There were no changes in the internal controls over financial reporting during the fourth quarter of the fiscal year covered by this report that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) under the Securities and Exchange Act of 1934). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation and fair presentation of financial statements for external purposes in accordance with GAAP and include those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures are being made only in accordance with authorizations of the management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations, any system of internal control over financial reporting, no matter how well designed, may not prevent or detect misstatements due to the possibility that a control can be circumvented or overridden or that misstatements due to error or fraud may occur that are not detected. Projections of the effectiveness to future periods are subject to the risk that the internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures included in such controls may deteriorate. The Company’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.
The Company has conducted an evaluation of the design and effectiveness of the Company’s system of internal control over financial reporting as of September 30, 2025, based on the framework set forth in ”Internal Control - Integrated Framework (2013)” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based upon such evaluation, the Company concluded that, as of September 30, 2025, the Company’s internal control over financial reporting was effective.

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information.
None.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10. Directors, Executive Officers and Corporate Governance.
For information with respect to the executive officers of the registrant, see “Executive Officers" section in the Proxy Statement for the 2026 Annual Meeting of Shareholders of Resources incorporated herein by reference. For information with respect to the Company’s directors and nominees and the Company’s Audit Committee, see Proposal 1 “Election of Directors of Resources” and “Report of the Audit Committee”, respectively, in the Proxy Statement for the 2026 Annual Meeting of Shareholders of Resources, which information is incorporated herein by reference. In addition, the Board of Directors has determined that Abney S. Boxley III and Jacqueline L. Archer are audit committee financial experts under applicable SEC rules.
For information regarding the process for identifying and evaluating candidates to be nominated as directors, see "Director Nominations" in the Proxy Statement for the 2026 Annual Meeting of Shareholders of Resources, which is incorporated herein by reference.
Information with respect to compliance with Section 16(a) of the Exchange Act, which is set forth under the caption "Delinquent Section 16(a) Reports" in the Proxy Statement for the 2026 Annual Meeting of Shareholders of Resources, is incorporated herein by reference.
The Company has adopted a Code of Ethics applicable to all of its officers, directors and employees. The Company has posted the text of its Code of Ethics on its website at www.rgcresources.com. The Board of Directors has adopted charters for the Audit, Compensation, and Governance and Nominating Committees of the Board of Directors. These documents may also be found on the Company’s website at www.rgcresources.com.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation.
The information set forth under "Compensation of Directors", "Compensation Discussion and Analysis" and "Report of the Compensation Committee" in the Proxy Statement for the 2026 Annual Meeting of Shareholders of Resources is incorporated herein by reference.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
For information pertaining to securities authorized for issuance under equity compensation plans, see Part II, Item 5 above.
The information pertaining to shareholders beneficially owning more than five percent of the registrant’s common stock and the security ownership of management, which is set forth under the caption “Security Ownership of Certain Beneficial Owners and Management" in the Proxy Statement for the 2026 Annual Meeting of Shareholders of Resources, is incorporated herein by reference.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Transactions, and Director Independence.
The information pertaining to director independence is set forth under the caption “Board of Directors and Committees of the Board of Directors” and pertaining to transactions with related persons is set forth under the caption "Transactions with Related Persons" in the Proxy Statement for the 2026 Annual Meeting of Shareholders of Resources, which information is incorporated herein by reference.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accounting Fees and Services.
The information set forth under the caption "Report of the Audit Committee" in the Proxy Statement for the 2026 Annual Meeting of Shareholders of Resources is incorporated herein by reference.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits and Financial Statement Schedules.
(a) List of documents filed as part of this report:
1. Financial statements filed as part of this report:
All financial statements of the registrant as set forth under Item 8 of this Report on Form 10-K.
2. Financial statement schedules filed as part of this report:
All information is inapplicable or presented in the consolidated financial statements or related notes thereto.
3. Exhibits.
1 (a)
At Market Issuance Sales Agreement, dated March 5, 2020, between RGC Resources, Inc. and Janney Montgomery Scott LLC, as agent (incorporated herein by reference to Exhibit 1.1 on Form 8-K as filed March 5, 2020)
3 (a)
Articles of Incorporation as amended (incorporated herein by reference to Exhibit 3.1 on Form 8-K as filed February 5, 2020)
3 (b)
Amended and Restated Bylaws of RGC Resources, Inc. (incorporated herein by reference to Exhibit 3(b) on Form 8-K as filed on April 8, 2022)
4 (a)
Specimen copy of certificate for RGC Resources, Inc. common stock, $5.00 par value (incorporated herein by reference to Exhibit 4(a) of Registration Statement No. 33-67311, on Form S-4, filed with the Commission on November 13, 1998, and amended by Amendment No. 5, filed with the Commission on January 28, 1999)
4 (b)
RGC Resources, Inc., Amended and Restated Dividend Reinvestment and Stock Purchase Plan (incorporated herein by reference to Exhibit 4(b) on Form 10-K for the year ended September 30, 2014)
4 (c)
Description of RGC Resources, Inc. Common Stock (incorporated herein by reference to Exhibit 4(c) on Form 10-K for the year ended September 30, 2020)
10 (a)
P
Firm Transportation Agreement between East Tennessee Natural Gas Company and Roanoke Gas Company dated November 1, 1993 (incorporated herein by reference to Exhibit 10(a) of the Annual Report on Form 10-K for the fiscal year ended September 30, 1994 (SEC file number reference 0-367))
10 (b)
FSS Service Agreement by and between Columbia Gas Transmission LLC and Roanoke Gas Company dated July 23, 2019 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed July 26, 2019)
10 (c)
FTS Service Agreement by and between Columbia Gas Transmission LLC and Roanoke Gas Company dated July 23, 2019 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed July 26, 2019)
10 (d)
SST Service Agreement by and between Columbia Gas Transmission LLC and Roanoke Gas Company dated July 23, 2019 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed July 26, 2019)
10 (e)
FTS Service Agreement effective April 1, 2017 between Columbia Gas Transmission LLC and Roanoke Gas Company (incorporated herein by reference to Exhibit 10(f) on Form 10-K for the year ended September 30, 2017)
10 (f)
FTS-1 Service Agreement between Columbia Gulf Transmission LLC and Roanoke Gas Company dated March 7, 2022 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed March 11, 2022)
10 (g)
Negotiated Rate Letter Agreement with Columbia Gulf Transmission, LLC (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed March 11, 2022)
10 (h)
Gas Transportation Agreement, for use under FT-A rate schedule, between Tennessee Gas Pipeline Company and Roanoke Gas Company originally dated November 1, 1993 as amended (incorporated herein by reference to Exhibit 10(g) on Form 10-K for the year ended September 30, 2021)
10 (i)
P
Gas Transportation Agreement, for use under IT rate schedule, between Tennessee Gas Pipeline Company and Roanoke Gas Company dated September 1, 1993 (incorporated herein by reference to Exhibit 10(l) of the Annual Report on Form 10-K for the fiscal year ended September 30, 1994 (SEC file number reference 0-367))
10 (j)
Gas Storage Contract under rate schedule FS between Tennessee Gas Pipeline Company and Roanoke Gas Company originally dated November 1, 1993 as amended (incorporated herein by reference to Exhibit 10(i) on Form 10-K for the year ended September 30, 2021)
10 (k)
Gas Transportation Agreement, for use under FT-A rate schedule, between Tennessee Gas Pipeline Company and Roanoke Gas Company originally dated November 1, 1993 as amended (incorporated herein by reference to Exhibit 10(j) on Form 10-K for the year ended September 30, 2021)
10 (l)
Firm Transportation Agreement, For Use Under Rate Schedules FT-A and FT-GS, effective July 16, 2007, between East Tennessee Natural Gas Company and Roanoke Gas Company
10 (m)
Firm Transportation Agreement, For Use Under Rate Schedules FT-A and FT-GS, effective February 27, 2006, between East Tennessee Natural Gas Company and Roanoke Gas Company
10 (n)
FTA Gas Transportation Agreement effective November 1, 1998, between East Tennessee Natural Gas Company and Roanoke Gas Company (incorporated herein by reference to Exhibit 10(s)(s) on Form 10-K for the year ended September 30, 1998 (SEC file reference number 0-367))
10 (o)
Firm Storage Service Agreement effective March 19, 1997, between Virginia Gas Storage Company and Roanoke Gas Company (incorporated herein by reference to Exhibit 10(w)(w) on Form 10-K for the year ended September 30, 1998 (SEC file reference number 0-367))
10 (p)
Firm Storage Service Agreement by and between Roanoke Gas Company and Virginia Gas Pipeline Company, dated June 1, 2001 (incorporated herein by reference to Exhibit 10(b)(b)(b) on Form 10-K for the year ended September 30, 2001 (SEC file number reference 0-367))
10 (q)
FSS Service Agreement between Saltville Gas Storage Company L.L.C. and Roanoke Gas Company dated November 21, 2012 (incorporated herein by reference to Exhibit 10(o) on Form 10-K for the year ended September 30, 2017)
10 (r)
FSS Service Agreement between Saltville Gas Storage Company L.L.C. and Roanoke Gas Company dated March 25, 2008
10 (s)
Gas Transportation Agreement between Tennessee Gas Pipeline Company and Roanoke Gas Company originally dated November 1, 1999 as amended May 17, 2016 (incorporated herein by reference to Exhibit 10.3 of Form 10-Q as filed August 4, 2016)
10 (t)
Amendment dated May 17, 2016 to Gas Transportation Agreement originally dated December 1, 1993 between Tennessee Gas Pipeline Company and Roanoke Gas Company (incorporated herein by reference to Exhibit 10.1 of Form 10-Q as filed August 4, 2016)
10 (u)
Amendment dated May 17, 2016 to Gas Transportation Agreement originally dated November 1, 1993 between Tennessee Gas Pipeline Company and Roanoke Gas Company (incorporated herein by reference to Exhibit 10.2 of Form 10-Q as filed August 4, 2016)
10 (v)
Gas Transportation Agreement, for use under FT-A rate schedule between Midwestern Gas Transmission Company and Roanoke Gas Company dated March 11, 2019 (incorporated herein by reference to Exhibit 10.1 on Form 10-Q as filed May 6, 2019)
10 (w)
Amendment dated November 29, 2021 to Gas Transportation Agreement originally dated December 1, 1993 between Tennessee Gas Pipeline and Roanoke Gas Company (incorporated herein by reference to Exhibit 10(s)(s)(s)(s) on Form 10-K for the year ended September 30, 2021)
10 (x)
Transportation Service Agreement applicable to Firm Transportation Service under Rate Schedule FTS between Mountain Valley Pipeline, LLC and Roanoke Gas Company dated October 17, 2017, Amended Exhibits A and C dated April 15, 2024
10 (y)
Natural Gas Asset Management Agreement by and between Roanoke Gas Company and DTE Energy Trading, Inc. effective as of April 1, 2025 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed on March 31, 2025)
10 (z)
Guaranty Agreement by RGC Resources, Inc. in favor of DTE Energy Trading, Inc. effective April 1, 2025 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed on March 31, 2025)
10 (a)(a)
Gas Franchise Agreement between the City of Roanoke, Virginia, and Roanoke Gas Company dated December 14, 2015 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed December 16, 2015)
10 (b)(b)
Gas Franchise Agreement between the City of Salem, Virginia, and Roanoke Gas Company dated December 14, 2015 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed December 16, 2015)
10 (c)(c)
Gas Franchise Agreement between the Town of Vinton, Virginia, and Roanoke Gas Company dated November 17, 2015 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed December 16, 2015)
10 (d)(d)
RGC Resources Amended and Restated Key Employee Stock Option Plan (incorporated herein by reference to Exhibit 4(c) of Registration Statement No. 333-02455, Post Effective Amendment on Form S-8, filed with the Commission on July 2, 1999)
10 (e)(e)
RGC Resources, Inc. Amended and Restated Stock Bonus Plan (incorporated herein by reference to Exhibit 10 on Form 8-K filed on January 27, 2005 (SEC file reference number 0-367))
10 (f)(f)
RGC Resources, Inc. Amended And Restated Restricted Stock Plan for Outside Directors (incorporated herein by reference to Exhibit 10(i)(i) on Form 10-K for the year ended September 30, 2017)
10 (g)(g)
RGC Resources, Inc. Restricted Stock Plan (incorporated herein by reference to Exhibit 10.1 of Form 8-K as filed February 9, 2017)
10 (h)(h)
Nonqualified Deferred Compensation Plan Document (incorporated herein by reference to Exhibit 10.1 on Form 10-Q as filed February 11, 2021)
10 (i)(i)
RGC Resources, Inc. Recovery of Incentive Compensation Policy, effective as of October 1, 2023 (incorporated herein by reference to Exhibit 99.1 on Form 10-Q as filed February 6, 2024)
10 (j)(j)
Change in Control Agreement between RGC Resources, Inc. and Mr. Paul W. Nester effective May 1, 2023 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed April 27, 2023)
10 (k)(k)
Change in Control Agreement between RGC Resources, Inc. and Mr. Lawrence T. Oliver effective May 1, 2023 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed April 27, 2023)
10 (l)(l)
Change in Control Agreement between RGC Resources, Inc. and Mr. Carl J. Shockley, Jr. effective May 1, 2023 (incorporated herein by reference to Exhibit 10.4 on Form 8-K as filed April 27, 2023)
10 (m)(m)
Change in Control Agreement between RGC Resources, Inc. and Mrs. C. Brooke Miles effective May 1, 2023 (incorporated herein by reference to Exhibit 10.5 on Form 8-K as filed April 27, 2023)
10 (n)(n)
Change in Control Agreement between RGC Resources, Inc. and Mr. Timothy J. Mulvaney effective February 1, 2024 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed February 2, 2024)
10 (o)(o)
Note Purchase Agreement for 4.26% Senior Guaranteed Notes due September 18, 2034 in the original principal amount of $30,500,000 in favor of The Prudential Insurance Company of America, PAR U Hartford Life & Annuity Comfort Trust and PRUCO Life Insurance Company of New Jersey (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed August 4, 2014)
10 (p)(p)
Unconditional Parent Guaranty by RGC Resources, Inc. in favor of each of the holders of the notes: The Prudential Life Insurance Company of America, PAR U Hartford Life & Annuity Comfort Trust and PRUCO Life Insurance Company of New Jersey (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed August 4, 2014)
10 (q)(q)
4.26% Senior Guaranteed Notes due September 18, 2034 in the original principal amount of $15,250,000 in favor of The Prudential Insurance Company of America (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed September 23, 2014)
10 (r)(r)
4.26% Senior Guaranteed Notes due September 18, 2034 in the original principal amount of $9,700,000 in favor of PAR U Hartford Life & Annuity Comfort Trust (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed September 23, 2014)
10 (s)(s)
4.26% Senior Guaranteed Notes due September 18, 2034 in the original principal amount of $5,550,000 in favor of PRUCO Life Insurance Company of New Jersey (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed September 23, 2014)
10 (t)(t)
Private Shelf Agreement by and between Roanoke Gas Company and Prudential Investment Management, Inc. for the pre-authorization to issue notes up to $29,500,000 in total during the term of the agreement (incorporated herein by reference to Exhibit 10.4 on Form 8-K as filed October 4, 2017)
10 (u)(u)
Second Amendment to Private Shelf Agreement dated as of December 6, 2019 (incorporated herein by reference to Exhibit 10.4 on Form 8-K as filed December 9, 2019)
10 (v)(v)
Third Amendment to Private Shelf Agreement dated as of December 6, 2022 (incorporated by reference to Exhibit 10.1 on Form 8-K as filed December 7, 2022)
10 (w)(w)
Unsecured Note in the original principal amount of $4,000,000 by and between Roanoke Gas Company and PRUCO Life Insurance Company of New Jersey, dated October 2, 2017 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed October 4, 2017)
10 (x)(x)
Unsecured Note in the original principal amount of $4,000,000 by and between Roanoke Gas Company and Prudential Arizona Reinsurance Captive Company, dated October 2, 2017 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed October 4, 2017)
10 (y)(y)
Unconditional Parent Guaranty by RGC Resources, Inc. in favor of each of the holders of the notes: The PRUCO Life Insurance Company of New Jersey and the Prudential Arizona Reinsurance Captive Company (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed October 4, 2017)
10 (z)(z)
Unsecured Note in the original principal amount of $5,000,000 by and between Roanoke Gas Company and Highmark, Inc. dated March 28, 2019 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed March 29, 2019)
10 (a)(a)(a)
Unsecured Note in the original principal amount of $3,000,000 by and between Roanoke Gas Company and Prudential Arizona Reinsurance Term Company dated March 28, 2019 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed March 29, 2019)
10 (b)(b)(b)
Unsecured Note in the original principal amount of $2,000,000 by and between Roanoke Gas Company and The Prudential Insurance Company of America dated March 28, 2019 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed March 29, 2019)
10 (c)(c)(c)
Unconditional Guaranty Agreement by and between RGC Resources, Inc. and Prudential Investment Management and each Prudential Affiliate which is a party to the borrowing (incorporated herein by reference to Exhibit 10.4 on Form 8-K as filed March 29, 2019)
10 (d)(d)(d)
**
Third Amended and Restated Limited Liability Company Agreement of Mountain Valley Pipeline, LLC dated April 6, 2018 (incorporated by reference to Exhibit 10.1 on the Quarterly Report on Form 10-Q as filed May 7, 2018)
10 (e)(e)(e)
Guaranty Agreement by RGC Resources, Inc. in favor of Mountain Valley Pipeline, LLC (incorporated herein by reference to Exhibit 10.2 on Form 10-Q as filed May 7, 2018)
10 (f)(f)(f)
Letter Agreement dated May 4, 2023, between MVP Holdco, LLC and RGC Midstream, LLC (incorporated by reference to Exhibit 10.1 on Form 10-Q filed on May 5, 2023)
10 (g)(g)(g)
Unsecured Note in the original principal amount of $5,000,000 by and between Roanoke Gas and Prudential Arizona Reinsurance Universal Company, dated December 6, 2019 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed December 9, 2019)
10 (h)(h)(h)
Unsecured Note in the original principal amount of $5,000,000 by and between Roanoke Gas and Prudential Arizona Reinsurance Universal Company, dated December 6, 2019 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed December 9, 2019)
10 (i)(i)(i)
Unconditional Guaranty Agreement by and between RGC Resources, Inc. and Prudential Investment Management and each Prudential Affiliate which is a party to the borrowings dated December 6, 2019 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed December 9, 2019)
10 (j)(j)(j)
Delayed Draw Term Note in the principal amount of $15,000,000 by Roanoke Gas Company with Wells Fargo Bank, N.A. dated as of August 20, 2021 (incorporated by reference to Exhibit 10.1 on Form 8-K as filed August 26, 2021)
10 (k)(k)(k)
Swap Agreement by and between Roanoke Gas Company and Wells Fargo Bank, N.A., executed on August 20, 2021 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed August 26, 2021)
10 (l)(l)(l)
Promissory Note (Revolving Loan) in the principal amount of $25,000,000 by Roanoke Gas Company with Pinnacle Bank, dated March 24, 2023 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed March 28, 2023)
10 (m)(m)(m)
Amendment to Promissory Note and Loan Agreement by Roanoke Gas Company with Pinnacle Bank, dated March 31, 2024 (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed April 3, 2024)
10 (n)(n)(n)
Amended and Restated Promissory Note (Term Loan) in the principal amount of $10,000,000 by Roanoke Gas Company with Pinnacle Bank, dated March 24, 2023 (effective as of April 1, 2023) (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed March 28, 2023)
10 (o)(o)(o)
Amended and Restated Loan Agreement by and between Roanoke Gas Company and Pinnacle Bank, dated March 24, 2023 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed March 28, 2023)
10 (p)(p)(p)
Amended and Restated Guaranty Agreement by RGC Resources, Inc. with Pinnacle Bank, dated March 24, 2023 (incorporated herein by reference to Exhibit 10.4 on Form 8-K as filed March 28, 2023)
10 (q)(q)(q)
Amended Swap Agreement by and between Roanoke Gas Company and Pinnacle Bank, dated April 3, 2023 (effective April 1, 2023) (incorporated herein by reference to Exhibit 10.1 on Form 8-K as filed April 4, 2023)
10 (r)(r)(r)
Amended and Restated Promissory Note in the principal amount of $30,000,000 by Roanoke Gas Company with Pinnacle Bank, dated March 31, 2025 (incorporated herein by reference to Exhibit 10.3 on Form 8-K filed March 31, 2025)
10 (s)(s)(s)
Second Amendment to Loan Agreement by Roanoke Gas Company with Pinnacle Bank, dated March 31, 2025 (incorporated herein by reference to Exhibit 10.4 on Form 8-K filed March 31, 2025)
10 (t)(t)(t)
Swap Agreement by and between RGC Midstream, LLC and Atlantic Union Bank, dated June 12, 2019 (incorporated herein by reference to Exhibit 10.4 on Form 8-K as filed June 17, 2019)
10 (u)(u)(u)
Credit Agreement by and between RGC Midstream, LLC, Atlantic Union Bank and CoBank, ACB, dated as of September 5, 2025 (incorporated herein by reference to Exhibit 10.1 on Form 8-K filed September 9, 2025)
10 (v)(v)(v)
Guaranty by RGC Resources, Inc. with Atlantic Union Bank, dated as of September 5, 2025 (incorporated herein by reference to Exhibit 10.2 on Form 8-K filed September 9, 2025)
10 (w)(w)(w)
Interest Rate Swap Confirmation by and between RGC Midstream, LLC and Atlantic Union Bank, executed on September 5, 2025 (incorporated herein by reference to Exhibit 10.3 on Form 8-K filed September 9, 2025)
10 (x)(x)(x)
Interest Rate Swap Confirmation by and between RGC Midstream, LLC and CoBank, executed on September 5, 2025 (incorporated herein by reference to Exhibit 10.4 on Form 8-K filed September 9, 2025)
10 (y)(y)(y)
Loan Agreement by and between RGC Midstream, LLC and Atlantic Union Bank, dated as of September 5, 2025 (incorporated herein by reference to Exhibit 10.5 on Form 8-K filed September 9, 2025)
10 (z)(z)(z)
Guaranty by RGC Resources, Inc. with Atlantic Union Bank, dated as of September 5, 2025 (incorporated herein by reference to Exhibit 10.6 on Form 8-K filed September 9, 2025)
Annual Report
Revised Code of Ethics (incorporated herein by reference to Exhibit 14.1 on Form 8-K as filed April 27, 2023)
Insider Trading Policy
Subsidiaries of the Company
Consent of Deloitte & Touche LLP
31.1
Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer
31.2
Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer
32.1
*
Section 1350 Certification of Principal Executive Officer
32.2
*
Section 1350 Certification of Principal Financial Officer
101.INS
Inline XBRL Instance Document (the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document)
101.SCH
Inline XBRL Taxonomy Extension Schema Document
101.CAL
Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF
Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB
Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE
Inline XBRL Taxonomy Extension Presentation Linkbase Document
Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)
* These certifications are being furnished solely to accompany this annual report pursuant to 18 U.S.C. Section 1350, and are not being filed for purposes of Section 18 of the Securities Exchange Act of 1934 and are not to be incorporated by reference into any filing of the registrant, whether made before or after the date hereof, regardless of any general incorporation language in such filing.
** Confidential treatment has been granted with respect to portions of this exhibit, indicated by asterisks, which has been filed separately with the Securities and Exchange Commission.
P These original exhibits were filed with the SEC in paper form and therefore are not hyper-linked to the original filing.