RGC RESOURCES INC - Annual Report: 2021 (Form 10-K)

GLOSSARY OF TERMS

Cautionary Note Regarding Forward Looking Statements

This report contains forward-looking statements that relate to future transactions, events or expectations. In addition, Resources may announce or publish forward-looking statements relating to such matters as anticipated financial performance, business prospects, technological developments, new products, research and development activities and similar matters. These statements are based on management’s current expectations and information available at the time of such statements and are believed to be reasonable and are made in good faith. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements. In order to comply with the terms of the safe harbor, the Company notes that a variety of factors could cause the Company’s actual results and experience to differ materially from the anticipated results or expectations expressed in the Company’s forward-looking statements. The risks and uncertainties that may affect the operations, performance, development and results of the Company’s business include, but are not limited to those set forth in the following discussion and within Item 1A “Risk Factors” of this Annual Report on Form 10-K. All of these factors are difficult to predict and many are beyond the Company’s control. Accordingly, while the Company believes its forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. When used in the Company’s documents or news releases, the words “anticipate,” “believe,” “intend,” “plan,” “estimate,” “expect,” “objective,” “projection,” “forecast,” “budget,” “assume,” “indicate” or similar words or future or conditional verbs such as “will,” “would,” “should,” “can,” “could” or “may” are intended to identify forward-looking statements.

Forward-looking statements reflect the Company’s current expectations only as of the date they are made. The Company assumes no duty to update these statements should expectations change or actual results differ from current expectations except as required by applicable laws and regulations.

PART I

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, Midstream and Diversified Energy.

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 2% of consolidated revenues.

In July 2015, the Company formed Midstream for the purpose of becoming a 1% 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.

Diversified Energy is currently inactive.

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 for the utility operations is defined as revenues less cost of gas. 

Roanoke Gas’ regulated natural gas distribution business accounted for more than 98% of Resources total revenues for fiscal years ending September 30, 2021 and 2020. The tables above indicate that residential customers represent over 91% of the Company’s customer total; however, they represent less than 40% of the total gas volumes delivered and more than half of the Company’s consolidated revenues and margin. Industrial customers include primarily transportation customers that purchase their natural gas requirements 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 relates only to transportation service, and not to the purchase of natural gas, causing total revenues generated by these deliveries to be less than 10%, although they represent more than 30% of total natural gas volumes and between 11% and 12% 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 Company’s annual consolidated financial statements.

The Company’s residential and commercial sales are seasonal and temperature-sensitive as the majority of the gas sold by Roanoke Gas to these customers is used for heating. For the fiscal year ended September 30, 2021, approximately 63% of the Company’s total DTH of natural gas deliveries and 73% of the residential and commercial deliveries were made in the five-month period of November through March.

Roanoke Gas relies on multiple interstate pipelines including those operated by Columbia Gas Transmission Corporation, LLC and Columbia Gulf Transmission Corporation, LLC (together “Columbia”), and East Tennessee Natural Gas, LLC (“East Tennessee”), Tennessee Gas Pipeline, Midwestern Gas Transmission Company and Saltville Gas Storage Company, LLC ("Saltville"), to transport natural gas from the production and storage fields to Roanoke Gas’ distribution system. Roanoke Gas is directly served by two pipelines, Columbia and East Tennessee. Columbia historically has delivered more than 65% of the Company’s required gas supply, with East Tennessee delivering the balance. The rates paid for interstate natural gas transportation and storage services are established by tariffs approved by FERC. The current pipeline contracts expire at various times from 2022 to 2027. 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 78,606 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 103,606 DTH on a single winter day.

The Company currently contracts with Sequent Energy Management, L.P. 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 Sequent contract was extended to March 31, 2023.

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.

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 franchise agreements were renewed for a 20-year term, set to expire December 31, 2035. In 2019, the SCC issued a final order granting a CPCN to furnish gas to all of Franklin County. Unlike the CPCNs for the other counties served by Roanoke Gas, the Franklin County CPCN will terminate within five years of the date of the order if Roanoke Gas does not furnish gas service to the designated service area. Roanoke Gas plans to serve the Franklin County area with natural gas delivered through the MVP, once MVP is placed into service.

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, coal, wind and solar. 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 provide upward pressure on the price of natural gas. Currently, increased demand and lower storage levels are placing upward pressure on the price of natural gas.

Competition from renewable energy sources such as solar and wind is likely to increase as the political environment currently favors these energy sources through incentives or by placing restrictions on emissions from the burning of fossil fuels. Nevertheless, the Company continues to see a demand for natural gas. Growth in residential and commercial service has been strong as the Company continues to grow 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 at the federal, state and local levels. 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, 2021, Resources had 99 full-time employees, of which 17 employees, or 17%, belonged to the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial International Union, Local No. 515 and were represented under a collective bargaining agreement. The union has been in place at the Company since 1952. The current collective bargaining agreement became effective August 1, 2020 and expires July 31, 2022. Management maintains an amicable relationship with the union.

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 is facing retirements of key personnel over the next several years.

With respect to the COVID-19 pandemic, the Company continues to evaluate and implement its pandemic plan to ensure the continuation of safe and reliable service to customers and to maintain the safety of the Company's employees.

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. You may read and copy these filings with the SEC at the SEC public reference room at 100 F Street, NE, Washington, D.C. 20549. Due to COVID-19, the SEC public reference room is closed until further notice. Questions about information available from the public reference room should be directed to SEC staff at library@sec.gov or by calling 1-202-551-5450. 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.                    

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, financial and general:

OPERATIONAL RISKS

            Availability of sufficient and reliable pipeline capacity.

The Company is currently served directly by two interstate pipelines. These two 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 both 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. 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 and thereby limiting future earnings potential.

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 may be vulnerable to an attack by individuals or organizations intending to disrupt the operations of the Company. Such an attack or cyber-security 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; 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 a successful 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. Resources maintains cyber-insurance coverage, which does not protect the Company from cyber incidents but does provide some level of protection to mitigate the financial impacts resulting from such attacks.

Supply disruptions due to weather or other forces.

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. Decreased supplies could result in an inability to meet customer demand, service new franchise areas or lead to higher prices and/or service disruptions. Disasters could increase costs to repair damaged facilities and result in delays to restore service to interrupted customers as well as lead to additional governmental regulations that may limit production activity and/or increase production and transportation costs.

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 lower storage balances and production levels, are placing upward pressure on natural gas commodity prices.  If these factors continue for an extended period of time, higher natural gas prices could result in declining sales 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 may have key personnel retire over the next several years, the failure to transition the skills and knowledge of the departing employees to qualified existing or new employees could increase operating costs and expose the Company to other operational, reputational and financial risks.

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. Any of these factors could adversely affect earnings.

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 needs to install new pipeline facilities and maintain, expand or upgrade 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. This could include any potential customer growth or system reliability enhancement resulting from connection to the MVP. Any of these factors could negatively impact earnings.

Impact of weather conditions and related regulatory mechanisms.

The Company’s revenues and earnings are dependent upon weather conditions. The Company’s rate structure currently has a WNA factor that results in either a recovery or refund of revenues due to variation from the 30-year average for heating degree-days. If the WNA mechanism were removed from its rate structure, the Company would be exposed to a much greater risk related to weather variability resulting in earnings volatility. 

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 natural gas to be a better value than other energy options and elect to install heating systems that use an energy source other than natural gas.

Inability to renew or obtain new franchise agreements or certificates of public convenience.

Roanoke Gas Company holds either franchises or CPCNs to provide natural gas to customers in its service territory. The franchises are granted by the local municipalities and the CPCNs are granted by the SCC. The ability to renew such agreements is important to the long-term operations of the Company and the ability to obtain new franchises or CPCNs is fundamental to expanding the Company’s service territory. Failure to renew these agreements could result in significant impact to future earnings and the inability to obtain new franchises or CPCNs for new service areas could negatively impact future earnings growth.

REGULATORY RISKS

Environmental laws or regulations associated with climate change.

Several federal and state legislative and regulatory initiatives have been proposed and passed 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. Passage of new environmental legislation or implementation of regulations that mandate 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 emissions, resulting in reduced deliveries and 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.

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. If the SCC did not authorize rates that provided for the timely recovery of costs or a reasonable rate of return on investment in natural gas distribution facilities, earnings could be negatively impacted. 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.

Compliance with and changes in tax laws.

The Company is subject to extensive tax laws and regulations. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future.

Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional taxes as well as interest and penalties.

FINANCIAL RISKS

Investment in Mountain Valley Pipeline, LLC.

The success of the Company's investment in the LLC is predicated on several key factors including but not limited to the ability of all investors to meet their capital calls when due, timely state and federal approvals and completing the construction of the pipeline. Any significant delay, cost over-run or the failure to receive the requisite approvals on a timely basis, or at all, could have a significant effect on the Company's earnings and financial position.

Although the LLC initially received the necessary federal and state permits to construct the pipeline, progress on the MVP has been hindered by several legal and regulatory obstacles as the Fourth Circuit, FERC and other governmental agencies have issued stays, stop orders or delayed authorizations affecting portions or all of the project pending resolution of issues or concerns raised as the project has progressed. The LLC is currently waiting on resolution of the remaining permits needed for the streams and wetlands crossings. FERC has not yet granted a revised authorization to complete construction work in a 8 mile section of the pipeline route. The LLC also needs authorizations from the Bureau of Land Management and the United States Forest Service and resolution of challenges to the Biological Opinion and Incidental Take Statement issued by the U.S. Fish and Wildlife Service.

Several of the prior issues have been resolved; however, the ongoing obstacles as discussed above continue to cause delays in construction and have resulted in significantly higher projected costs and an extended targeted in-service date for the pipeline. These cost overruns may not be approved for recovery or be recovered through other regulatory mechanisms, and the LLC could be obligated to make delay or termination payments or be responsible for other contractual damages. The LLC could also experience the loss of tax incentives, or delayed or diminished returns, and could be required to write-off all or a portion of its investment in the project. New or extended regulatory, legislative or judicial actions or challenges could lead to additional delays and even higher costs, which could affect future returns for the LLC 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.

In addition, there are numerous risks facing the LLC, which can adversely affect the Company's earnings and financial performance through its investment. The LLC's ability to retain contract crews to complete construction of the pipeline, the inability to obtain or renew ancillary licenses, rights-of-way, permits or other approvals and opposition from pipeline opponents and environmental groups could all influence the successful completion of the pipeline. Should the LLC be unable to adequately address these issues, the LLC’s business, financial condition, results of operations and prospects could be adversely affected, which could materially impact the financial condition and results of operations of the Company. Any failure to negotiate successful project development agreements for new facilities with third parties could have similar results.

Once in operation, 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 and personal injury damage, 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 could have a material adverse effect on the LLC’s business, 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 facility start-up operations, such as whether the facility will achieve projected operating performance on schedule and otherwise as planned. The LLC’s business, financial condition, results of operations and prospects can be materially adversely affected by weather conditions, including, but not limited to, the impact of severe weather. Threats of terrorism and catastrophic events resulting from terrorism, 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.

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, short-term 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 capital outlays and funding of the LLC investment. The ability of the Company to maintain and renew its line-of-credit and to secure longer-term financing 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.

Pandemic Outbreak.

A pandemic event such as COVID-19 or other similar diseases could cause a significant economic restriction or recession negatively impacting the Company’s financial position, results of operations and cash flows. Depending on the duration of these impacts, the liquidity of the Company could be strained, reducing the Company’s ability to complete infrastructure investments and its ability to safely and reliably serve its customers.

Impact from commercial customers: In an effort to reduce the spread of disease, businesses, either on their own or by government mandates, may close or reduce operations to limit contact with the contagion. A reduction in business activity could result in lower natural gas consumption for both production activities as well as space heating, thereby reducing revenues and gross profit. The closing or reduction in operations by businesses, whether temporary or prolonged, could result in a permanent loss of some commercial customers.

Impact from residential customers: The closing of businesses may result in job layoffs or other reductions in employee numbers and/or working hours, thus reducing or eliminating customers’ ability to pay their utility bills and resulting in increased bad debt expense.

Impact on suppliers: A pandemic event could reduce the ability of the Company’s suppliers to supply a sufficient level of natural gas limiting our ability to meet customer demands.

Impact to the Company's employees: Orders by government bodies could result in employees of the Company being required to limit contact with customers or work remotely, thus not allowing them to complete tasks normally requiring a physical presence. Also, if a significant number of employees were to contract the virus or be quarantined, the Company may not be able to complete key or critical tasks, not limited to, but including key financial, reporting, and operational controls.

Impact from SCC actions: The SCC could issue orders in response to a pandemic event that result in increased regulatory oversight, operational mandates or restrictions on normal business activities. Any such action could result in increased operating costs or other financial or operational burdens that may negatively impact the Company's results of operations or financial position.

Impact on financing capabilities: A prolonged economic shutdown due to a pandemic could stress the banking system, thereby limiting the Company’s ability to obtain financing on commercially reasonable terms, which could lead to higher interest costs. Furthermore, a distressed equity market could limit the ability to raise capital through the issuance of Resources’ equity instruments due to depressed prices and low trading volumes.

Post-retirement benefits and related funding of obligations.

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.

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 the Company has in place. With respect to interest rate risk, the Company has been operating in a relatively low interest rate environment for both short and long-term interest rates. However, increasing interest rates could adversely affect the Company’s future financial results.

GENERAL RISKS

General downturn in the economy or prolonged period of slow economic recovery.

A weak or poorly performing economy can negatively affect the Company’s profitability. An economic downturn can result in loss of commercial and industrial customers due to plant closings, a loss of residential customers as well as slow or declining growth in new customer additions, all of which would result in reduced sales volumes and lower revenues. An economic downturn could also result in rising unemployment and other factors that could lead to a loss of customers and an increase in customer delinquencies and bad debt expense.

Insurance coverage may not be sufficient.

The Company currently has liability and property insurance to cover a variety of exposures and risks. The insurance policies supporting said coverages are subject to certain limits and deductibles. Insurance coverage for risks against which the Company and its industry peers typically insure may not be offered in the future or such policies may expand exclusions that limit the amount of coverage or remove certain risks completely as insured events. Furthermore, litigation awards continue to increase and the limits of insurance may not keep pace accordingly. The proceeds received from any such insurance may not be paid in a timely manner. The occurrence of any of the foregoing could have a material adverse effect on the Company’s financial position, results of operations and cash flows.

Item 1B.    Unresolved Staff Comments.

None.

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 as categorized by natural gas utilities. The Company has approximately 1,157 miles of transmission and distribution pipeline with transmission and distribution plant representing 89% of the total utility plant investment. The transmission and distribution pipelines are located on or under public roads and highways or private property for which the Company has obtained the legal authorization and rights to operate.

Roanoke Gas currently owns and operates six 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 also 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.

The Company’s executive, accounting and business offices, along with its maintenance and service 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.

Item 3.    Legal Proceedings.

The Company is not known to be a party to any pending legal proceedings.

Item 4.    Mine Safety Disclosures.

Not applicable.

PART II

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.

As of November 19, 2021, there were 1,030 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, 2021:

Item 6.    Selected Financial Data.

Not applicable.

Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations.

COVID-19

As was discussed under Item 1A "Risk Factors" above, COVID-19 and the resulting pandemic continues to impact the local, state, national and global economies. Supply chain disruptions, labor shortages and inflation have supplanted quarantines and government restrictions as the primary examples of matters impacting economic conditions.  Significant progress was made in distributing and administering vaccines to the public through September 30, 2021, which has allowed a return to mostly normal operating conditions. Most restrictions implemented as a result of the pandemic have been eased, including Virginia’s state of emergency, allowing for increased business, recreational and travel activities. Natural gas consumption by the Company’s commercial customers has largely returned to pre-pandemic levels. However, the easing of restrictions and the existence of variant strains of COVID-19 may lead to a rise in infections, which could result in the reinstatement of some or all of the restrictions previously in place. Management continues to monitor current conditions to ensure the continuation of safe and reliable service to customers and to maintain the safety of the Company's employees. 

See the Regulatory section below for information regarding the service disconnection moratorium, CARES Act and ARPA funds.

The full extent to which the COVID-19 pandemic will impact the Company depends on future developments, which are highly uncertain and cannot be reasonably predicted, including the increase or reduction in governmental restrictions to businesses and individuals, the potential resurgence of the virus, including variants, as well as efficacy of the vaccines.

Cyber Risk

Cyber attacks are a constant threat to businesses and individuals. The Company remains focused on these threats and is committed to safeguarding its information technology systems. These systems contain confidential customer, vendor and employee information as well as important operational financial data. There is risk associated with unauthorized access of this information with a malicious intent to corrupt data, cause operational disruptions or compromise information. Management continuously monitors access to these systems and believes it has security measures in place to protect these systems from cyber attacks and similar incidents; however, there can be no guarantee that an incident will not occur. In the event of a cyber incident, the Company will execute its Security Incident Response Plan. The Company maintains cyber insurance to mitigate financial costs that may result from a cyber incident.

Overview

Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 62,600 residential, commercial and industrial customers in Roanoke, Virginia, and the surrounding localities, through its Roanoke Gas subsidiary. Roanoke Gas also provides certain unregulated services. As a wholly-owned subsidiary of Resources, Midstream is a more than 1% investor in the MVP and a less than 1% investor in Southgate. More information regarding the investment in MVP is provided under the Equity Investment in Mountain Valley Pipeline section below.

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, excluding equity in earnings of MVP, are derived from the sale and delivery of natural gas to Roanoke Gas customers based on rates 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.

The Company is also subject to federal regulation from the Department of Transportation in regard to the construction, operation, maintenance, safety and integrity of its transmission and distribution pipelines. FERC 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 October 10, 2018, Roanoke Gas filed a general rate application requesting an annual increase in customer non-gas base rates. Roanoke Gas implemented the interim non-gas rates contained in its rate application for natural gas service rendered to customers on or after January 1, 2019. On January 24, 2020, the SCC issued its final order on the general rate application, granting Roanoke Gas an annualized increase in non-gas base rates of $7.25 million and an authorized rate of return on equity of 9.44%. As a result, the Company refunded $3.8 million to its customers in March 2020, representing the excess revenues collected plus interest for the difference between the final approved rates and the interim rates billed since January 1, 2019. The order also directed the Company to write-off $317,000 of ESAC assets that were not subject to recovery under the final order.

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 in 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 and PGA.

The Company’s non-gas base rates provide for the recovery of non-gas related expenses and a reasonable return to shareholders. These rates are determined based on the filing of a formal non-gas rate application 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 currently in place. The investment in replacing and upgrading existing infrastructure is generally not recoverable until a formal rate application is filed to include the additional investment, and new non-gas base rates are approved. The SAVE Rider provides the Company with a mechanism through which it recovers the cost related to SAVE qualified infrastructure investments on a prospective basis, until a formal rate application is filed to incorporate the recovery of these costs in non-gas rates.  The SAVE Plan and Rider were reset effective January 1, 2019, when the recovery of all prior SAVE Plan investment was incorporated into the current non-gas rates.  Accordingly, SAVE Plan revenues increased to $2,487,000 in fiscal 2021 from $1,272,000 in fiscal 2020.  The current SAVE Plan is focused on replacing first generation, pre-1973 plastic pipe and other qualifying infrastructures projects. Additional information regarding the SAVE Plan and Rider is provided under the Regulatory section.

The WNA model 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 price protection when the weather is colder than normal. The WNA allows the Company to recover from its customers the lost margin (excluding gas costs) from the impact of weather that is warmer than normal and correspondingly requires the Company to refund the excess margin earned for weather that is colder than normal. Any billings or refunds related to the WNA are completed following each WNA year, which runs from April to March. The Company recorded approximately $1,196,000 and $1,193,000 in additional revenue from the WNA for weather that was approximately 8% warmer than normal for the fiscal years ended September 30, 2021 and 2020.  The number of heating degree days used to determine normal will change annually as a new year is added to the 30-year period and the oldest year is removed. As a result of adding recent warmer than normal years to replace historical colder years, the number of heating degree days that defines normal has declined over the last several years.

The Company also has an approved rate structure in place 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.  Total ICC revenues were $396,000 and $389,000 for the fiscal years ended September 30, 2021 and 2020, respectively.  Average inventory balances varied modestly between periods; however, rising natural gas commodity prices near the end of the current fiscal year may lead to higher ICC revenues in fiscal 2022.

The cost of natural gas is a pass-through cost and is independent of the non-gas rates of the Company. 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 based on a quarterly filing, or more frequent if necessary, with the SCC. Once administrative approval is received, the Company adjusts the gas cost component of its rates to reflect the approved amount. As actual costs 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.

Roanoke Gas is required to submit an Annual Information Filing ("AIF") each year to the SCC. Included as part of this filing is an earnings test, which is required when the Company has certain regulatory assets. If the results of the earnings test indicate that the Company's regulatory earnings exceed the mid-point of its authorized return on equity range, then certain regulatory assets are written-down and recovery accelerated to the point where the actual return for the period adjusts to the mid-point of the range. The Company conducted preliminary earnings tests for fiscal 2021 and 2020 in preparation for the AIF filings in January of the subsequent years.  As a result of the preliminary earnings tests, Roanoke Gas expensed $217,000 in deferred COVID costs incurred during fiscal 2021, and fully amortized the remaining $525,000 balance of ESAC assets in fiscal 2020. 

Inflation and Rising Prices

Natural gas commodity, delivery and storage capacity costs comprise the single largest expense of the Company representing nearly 58% of fiscal 2021 total operating expenses.  Natural gas commodity prices have steadily increased through fiscal 2021 and natural gas futures for the upcoming winter heating season are double September prices.  Several factors have contributed to rising natural gas prices including lack of interstate pipeline development, demand rebounding as activity returns to pre-pandemic levels, lower inventory storage levels, increased demand for cleaner energy and lagging production from suppliers.  Roanoke Gas can recover rising natural gas costs through the PGA mechanism as noted above; however, in times of rapidly increasing costs, 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 to the potential for rising bad debts related to customers inability to pay higher natural gas bills.

Inflation affects the Company through increases in non-gas expenses such as labor costs, employee benefits, materials and supplies, contracted services and corporate insurance, among other areas.  As the country emerges from the pandemic, issues such as supply chain delays, labor shortages and limited availability of key or critical supplies have put upward pressure on several categories of the Company's non-gas expenses.  The Company recovers non-gas related costs through the non-gas portion of its tariff rates, which are adjusted through a non-gas rate application. Unlike the rate adjustments for the gas portion of rates which are done administratively, the non-gas rate application results in an inherent lag in non-gas expense recovery.  Therefore, authorized non-gas rates may not keep pace with the rising costs during inflationary periods.  Management must regularly evaluate the Company's operations, economic conditions and other factors to assess the need to apply for a non-gas rate adjustment.

Results of Operations

The analysis on the results of operations is based on the consolidated operations of the Company, which is primarily associated with the utility segment. Additional segment analysis is provided in areas where Midstream's investment in affiliates represents a significant component of the comparison.

The Company's operating revenues are affected by the cost of natural gas, as reflected in the consolidated income statement under the line item cost of gas - utility. The cost of natural gas is passed through to customers at cost, 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. Accordingly, management believes that gross utility margin, a non-GAAP financial measure defined as utility revenues less cost of gas, is a more useful and relevant measure to analyze financial performance. The term gross utility margin is not intended to represent or replace operating income, 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. The following results of operations analyses will reference gross utility margin.

Fiscal Year 2021 Compared with Fiscal Year 2020

The table below reflects operating revenues, volume activity and heating degree days.

Total gas utility operating revenues for the year ended September 30, 2021 increased by 20% from the year ended September 30, 2020 primarily due to higher natural gas commodity prices and pipeline storage fees, higher residential and commercial volumes and an increase in SAVE revenues, partially offset by lower transportation and interruptible volumes.  Rising natural gas commodity prices combined with higher transportation fees implemented by the Company's pipeline suppliers have resulted in a 41% per dth increase in the commodity component of revenue and a 38% per dth increase in the demand (pipeline and storage fees) component of revenue.  These higher gas costs are passed on to customers through the PGA mechanism.  The mostly weather sensitive residential and commercial natural gas deliveries increased by 6% on nearly the same number of heating degree days.  The higher deliveries reflect the increased demand for natural gas as economic conditions continue to improve and the economy emerges from last year's pandemic.  SAVE Plan revenues increased by $1,215,000  due to the ongoing investment in qualified SAVE infrastructure projects.  Transportation and interruptible volumes, primarily driven by business activity rather than weather, declined by 20% due to a single multi-fuel customer that switched its primary fuel from natural gas to an alternate energy source in response to rising natural gas prices.  In early fiscal 2020, this same customer switched from another energy source to natural gas as its primary fuel due to the favorable pricing of natural gas.  Excluding the multi-fuel customer's usage from both periods, total transportation and interruptible volumes would have increased by 3% on a comparative basis.  Non-utility revenues decreased due to the completion of a significant long-term contract in fiscal  2020.

Gross utility margin increased over the prior fiscal year primarily as a result of the aforementioned higher SAVE revenues and increase in residential and commercial volumes and customer base charges more than offsetting the reduction in transportation and interruptible deliveries. Total volumetric margin increased for the reasons mentioned above as the increase in residential and commercial DTH sales more than offset the decline in lower-margin interruptible and transportation volumes.  The growth in customer base charge revenues reflect a combination of customer additions and the continuation of service to delinquent customers as a result of the disconnection moratorium, which ended August 30, 2021.  

The changes in the components of the gross utility margin are summarized below:

Operations and Maintenance Expense - Operations and maintenance expense decreased by $1,703,874 or 11%, from the prior year primarily due to the accelerated recovery of ESAC regulatory assets in fiscal 2020 and lower bad debt expense, partially offset by lower capitalized overheads. In accordance with the SCC's final order on the non-gas base rate application, the Company wrote-down $317,000 in ESAC assets last year that were not subject to recovery through the new rates.  In addition to the write-down of a portion of the ESAC assets in December 2019, Roanoke Gas accelerated the recovery of the remaining $525,000 balance of ESAC assets in September 2020 as a result of the earnings test performed by the Company. Bad debt expense declined by $964,000 due to the application of more than $400,000 in CARES Act funds to eligible COVID-19 impacted customers with past due balances and the pending receipt of $859,000 in ARPA funds to provide similar relief.  If not for the CARES Act and ARPA funds, bad debt expense would have increased significantly over last year's higher than normal levels.  Total capitalized overheads declined by $258,000 on a nearly $3 million reduction in capital expenditures related to project timing.

General Taxes - General taxes increased by $95,307, or 4%, primarily due to higher property taxes associated with a 5% increase in utility property.

Depreciation - Depreciation expense increased by $533,895, or 7%, corresponding to a similar increase in depreciable utility plant.

Equity in Earnings of Unconsolidated Affiliate - The equity in earnings of the MVP investment decreased by $3,147,320 as AFUDC activity ceased during the second fiscal quarter due to the cessation of growth construction activities by the LLC with limited construction resuming in April 2021 resulting in a much lower level of AFUDC recognized for the remainder of the year.  See the Equity Investment in Mountain Valley Pipeline section for additional information.

Other Income, net - Other income increased by $275,850 primarily due to a $449,000 decrease in the non-service cost components of net periodic benefit costs partially offset by $207,000 reduction in the equity portion of AFUDC on Roanoke Gas' two gate stations that will interconnect with the MVP.  Roanoke Gas temporarily stopped recognizing AFUDC effective January 2021 until such time construction activities resume on these stations.

Interest Expense - Total interest expense decreased by $47,273, or 1%, as a decline in the interest rate on the Company's variable rate debt offset higher total debt levels.  Total average debt outstanding increased by 14% to meet the funding needs of Roanoke Gas' capital projects and Midstream's continuing investment in MVP.  As a result of the declining interest rates on the Company's variable rate debt, the weighted-average interest rate fell by 12%.  Declines in other interest contributed to the lower expense levels including lower customer deposit interest.

Roanoke Gas' interest expense increased by $81,285 as total average debt outstanding increased by $8,500,000 associated with an increase in the borrowings under the line-of-credit. The average interest rate decreased slightly from 3.76% in fiscal 2020 to 3.48% in fiscal 2021. Roanoke gas capitalized $68,000 less in AFUDC during the current year due to the absence of construction activities on the two gate stations, which offset a $67,000 reduction in interest expense attributable to fiscal 2020's rate refund.

Midstream's interest expense decreased by $128,558 as the average interest rate on Midstream's total debt declined from 2.76% to 2.23% related to the variable interest rate credit facility more than offsetting a $6,900,000 increase in total average debt outstanding during the period.

Income Taxes - Income tax expense decreased by $101,598, or 3%, on a 4% decrease in pre-tax earnings. The effective tax rate was 24.1% for fiscal 2021 compared to 23.8% for fiscal 2020. The effective tax rate for both years is below the combined state and federal statutory rate of 25.74% due to the amortization of the excess deferred income taxes, the excess deductions related to restricted stock vesting, stock option exercises and the realization of certain tax credits. Income tax expense related to Midstream decreased by $780,000 due to the significant reduction in pre-tax earnings related to AFUDC from the MVP investment. The majority of the remaining $680,000 difference in income tax expense is related to the increase in pre-tax earnings of Roanoke Gas.

Net Income and Dividends - Net income for fiscal 2021 was $10,102,062 compared to $10,564,534 for fiscal 2020. Basic and diluted earnings per share were $1.22 in fiscal 2021 compared to $1.30 in fiscal 2020. Dividends declared per share of common stock were $0.74 in fiscal 2021 compared to $0.70 in fiscal 2020.

Capital Resources and Liquidity

Due to the capital intensive nature of the utility business, as well as the related weather sensitivity, the Company’s primary capital needs are the funding of its capital projects, investment in MVP, the seasonal funding of its natural gas inventories and accounts receivables and payment of dividends. To meet these needs, the Company relies on 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 $1.2 million in fiscal 2021 compared to a decrease of $1.3 million in fiscal 2020. The following table summarizes the categories of sources and uses of cash:

Cash Flows Provided by Operating Activities:

The seasonal nature of the natural gas 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 flow from operating activities decreased by nearly $1.3 million from the prior year. The decrease in cash flow provided by operations was primarily driven by the affects of increasing gas commodity prices and changes in certain regulatory assets and liabilities, partially offset by net income exclusive of noncash equity in earnings.

The table below summarizes the significant operating cash flow components:

Increasing natural gas commodity prices during 2021, resulted in reductions in operating cash in several areas. Higher accounts receivable balances, and increases in the under collection of gas costs, and rising gas in storage balances resulted in lower operating cash of $0.9, $1.4 and $2.9 million year over year, respectively. Income tax refunds not yet received, associated with the R&D credit study conducted by a third party consultant, caused prepaid income taxes to increase significantly year over year, resulting in a decrease in operating cash of $3 million. See Note 8 for more information regarding the R&D tax credit.

Operating cash decreases were partially offset by accounts payable and changes in certain regulatory assets and liabilities. Significantly higher accounts payable balances related to increasing natural gas commodity prices provided an additional $2.2 million in operating cash year over year. As there was no rate refund in fiscal 2021, operating cash improved $3.8 million.

Other significant non-cash changes include $1.1 million for allowance for doubtful accounts due to changes in bad debt reserves attributable to the pandemic and funding relief and $2.4 million related to the establishment of a regulatory liability for the R&D tax credit.

Cash Flows Used in Investing Activities:

Investing activities primarily consist of expenditures related to investment in Roanoke Gas' utility plant, 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, as well as the continued investment in the MVP. Roanoke Gas' expenditures were approximately $20 million and $22.9 million in fiscal 2021 and 2020, respectively. Roanoke Gas renewed 7.8 miles of main and 620 service lines and 9.6 miles of main and 592 service lines in fiscal years 2021 and 2020, respectively. The current SAVE Plan is focused on the replacement of pre-1973 first generation plastic pipe in addition to other SAVE related infrastructure. Furthermore, Roanoke Gas’ capital expenditures included costs to extend natural gas distribution mains and services to480 customers in fiscal 2021, compared to 448 customers in fiscal 2020. Depreciation covered approximately 43% and 35% of the current and prior year's capital expenditures, respectively, with the balance provided from other operating cash flows and financing activities.

Capital expenditures are expected to remain at or near current levels over the next three to five years as Roanoke Gas continues to focus on its SAVE Plan, which is expected to be completed by 2024, as well as customer growth and system expansion. The Company expects to utilize its credit facilities, as well as consider additional equity capital, to meet the funding requirements of these planned expenditures.

Investing cash flows also reflect the 2021 funding of $6 million for Midstream's participation in the LLC. Midstream's total expected funding requirement increased to between $60 and $62 million as discussed below, with anticipated cash investment for fiscal 2022 to be approximately $10.7 million. Funding for the investment in the LLC is provided through Midstream's credit facility and two unsecured notes in the combined amount of $24 million. More information regarding the credit facility is provided in Note 7 and under the Equity Investment in Mountain Valley Pipeline section below.

Cash Flows Provided by Financing Activities:

Financing activities generally consist of borrowings and repayments under credit agreements, issuance of stock and the payment of dividends. Net cash flows provided by financing activities were $15.5 million and $16.6 million in fiscal 2021 and 2020, respectively. The Company uses its line-of-credit to fund seasonal working capital needs and provide temporary financing for capital projects. The increase in financing cash flows was derived from Midstream's net borrowings of more than $8 million to finance its investment in MVP. The Company also realized $3.3 million from the issuance of common stock through its ATM program and $1.6 million from the issuance of stock through DRIP activity and the exercise of options. Cash out-flows for dividend payments exceeded $6.0 million as the annualized dividend rate increased from $0.70 to $0.74 per share. The Company’s consolidated capitalization was 41.5% equity and 58.5% long-term debt at September 30, 2021, exclusive of unamortized debt expense. This compares to 41.7% equity and 58.3% long-term debt at September 30, 2020. 

On October 29, 2021 Midstream entered into an unsecured promissory note in the principal amount of $8 million with an interest rate based on 30-day LIBOR plus 115 basis points maturing December 1, 2027. Related to this note, Midstream also entered into an interest rate swap agreement that effectively converts the variable rate note into a fixed rate instrument with an effective annual interest rate of 2.443%. The loan will convert into an installment loan with principal pay-down beginning in fiscal 2023. In addition, this note reduces the borrowing capacity defined by the Third Amendment to Credit Agreement and related Promissory Notes. The total borrowing capacity declined from $41 million to $33 million effective with the new promissory note.  All other terms of the Third Amendment to Credit Agreement remain unchanged.

On September 24, 2021, Roanoke Gas entered into an unsecured Delayed Draw Term Note in the principal amount of $10 million with an interest rate based on 30-day LIBOR plus 100 basis points maturing on October 1, 2028. Related to this note, the Company also entered into an interest rate swap agreement that effectively converts the variable rate note into a fixed rate instrument with an effective annual interest rate of 2.49%. The term note will fund in two installments of $5 million each on April 1, 2022 and October 1, 2022, respectively.

On August 20, 2021, Roanoke Gas entered into an unsecured Delayed Draw Term Note in the principal amount of $15 million with an interest rate of 1.20% above the 30-day SOFR Average per annum maturing on August 20, 2026. Related to this note, the Company also entered into an interest rate swap agreement that effectively converts the variable rate note into a fixed rate instrument with an effective annual interest rate of 2.00% The term note funded on October 1, 2021.

On March 25, 2021, Roanoke Gas renewed its unsecured line-of-credit agreement for a two-year term expiring March 31, 2023 with a maximum borrowing limit of $40 million. Amounts drawn against the agreement are considered to be non-current as the balance under the line-of-credit is not subject to repayment within the next 12-month period. The agreement has a variable-interest rate based on 30-day LIBOR plus 100 basis points and an availability fee of 15 basis points and provides multi-tiered borrowing limits aligned with the Company's seasonal borrowing demand. The Company's total available borrowing limits range from $14 million to $40 million.

On December 6, 2019, Roanoke Gas entered into unsecured notes in the aggregate principal amount of $10 million. These notes have a 10-year term from the date of issue at a fixed interest rate of 3.60%. The proceeds from these notes provided financing for Roanoke Gas' capital budget.

Roanoke Gas has private shelf agreements with two different financial institutions.  The first agreement, as amended, provides for the issuance of up to $40 million in unsecured notes in addition to the $28 million previously issued.  This shelf agreement will expire on December 6, 2022 unless extended.  The second agreement, effective September 30, 2020, provides for the issuance of up to $70 million in unsecured notes during its 5-year term expiring on September 30, 2025.  No funds were drawn on either of these agreements during fiscal 2021.

On February 14, 2020, Resources filed a prospectus with the SEC utilizing a shelf registration process where the Company may sell shares of common stock, in one or more offerings, of an aggregate amount up to $40 million. The prospectus was filed including a supplement allowing the Company to offer a portion of these shares, up to an aggregate of $15 million, utilizing the ATM approach as defined in Rule 415 under the Securities Act. The ATM Plan allows Resources flexibility in the frequency, timing and amount of share offerings in supplementing its capital funding needs. There were 142,726 shares issued through the ATM program during fiscal 2021.

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

Recent construction activity has been limited based on legal and regulatory challenges. Although certain permits and authorizations were received in the fourth quarter of fiscal 2020 and the first quarter of fiscal 2021, there remain pending challenges and authorization requests impacting current progress.

Following a comprehensive review of all outstanding stream and wetland crossings across the approximately 300-mile MVP project route, on February 19, 2021, the LLC submitted (i) a joint application package to each of the Huntington, Pittsburgh and Norfolk Districts of the U.S. Army Corps of Engineers (Army Corps) that requests an individual permit from the Army Corps to cross certain streams and wetlands utilizing open cut techniques (the Army Corps Individual Permit) and (ii) an application to amend the MVP project’s CPCN that seeks FERC authority to cross certain streams and wetlands utilizing alternative trenchless construction methods.

Related to seeking the Army Corps Individual Permit, on March 4, 2021, the LLC submitted applications to each of the West Virginia Department of Environmental Protection (WVDEP) and the Virginia Department of Environmental Quality (VADEQ) seeking Section 401 water quality certification approvals or waivers (such approvals or waivers, the State 401 Approvals).  Both the WVDEP and VADEQ submitted requests to the Army Corps for additional time to address the applications, and in late June 2021, the Army Corps granted the WVDEP and the VADEQ additional review time through November 29, 2021 and December 31, 2021, respectively.  In early June 2021, the FERC issued a notice of schedule for the LLC's CPCN amendment application. FERC issued its environmental assessment August 13, 2021.  Given that the expected permitting timelines for both the FERC and the Army Corps remain in-line with the LLC's expectations, the LLC continues to target a full in-service date for the MVP project in summer 2022 at a total project cost of approximately $6.2 billion (excluding AFUDC).

In order to complete the MVP project in accordance with the targeted full in-service date and cost, the LLC must, among other things, timely receive the Army Corps Individual Permit (as well as timely receive the State 401 Approvals and, as necessary, certain other state-level approvals) and timely receive authorization from the FERC to amend the CPCN to utilize alternative trenchless construction methods for certain stream and wetland crossings. The LLC also must (i) maintain and, as applicable, timely receive required authorizations, including authorization to proceed with construction, related to the Jefferson National Forest from the Bureau of Land Management, the U.S. Forest Service and the FERC; (ii) continue to have available the orders previously issued by the FERC modifying its prior stop work orders and extending the LLC’s prescribed time to complete the MVP project; (iii) timely receive authorization from the FERC to complete construction work in the portion of the project route currently remaining subject to the FERC's previous stop work order; and (iv) continue to be authorized to work under the Biological Opinion and Incidental Take Statement issued by the United States Department of the Interior’s Fish and Wildlife Service for the MVP project. In each case, any such foregoing or other authorizations must remain in effect notwithstanding any pending or future challenge thereto. Failure to achieve any one of the above items could lead to additional delays and higher project costs.

Resources' current earnings from the MVP investment are attributable to AFUDC income generated by the LLC. The LLC temporarily suspended the accrual of AFUDC on the project from January 1, 2021 (due to a temporary reduction in growth construction activities) through March 31, 2021.  Limited growth construction activities resumed in April 2021, and the LLC began accruing AFUDC associated with those activities.  It is expected that the accrual of AFUDC will be temporarily suspended again for the winter curtailment period, which is expected to begin around November 2021. Additionally, Roanoke Gas continues the suspension of AFUDC accruals on its two gate stations that will interconnect with the MVP until such time as construction activities resume on the respective gate stations.

Management conducted an assessment of its MVP investment in accordance with the provisions of ASC 323, Investments - Equity Method and Joint Ventures. This assessment included a third-party valuation. As a result of its evaluation, management has concluded that the investment is not currently impaired as of September 30, 2021. Furthermore, the LLC has conducted its own evaluation of the project and also concluded that no impairment exists as of September 30, 2021. Management will continue monitoring the status of the project for circumstances that may lead to future impairment, including any significant delays or denials of necessary permits and approvals. If necessary, the amount and timing of any future impairment would be dependent on the specific circumstances at the time of evaluation.

In April 2018, the LLC announced the MVP Southgate project and submitted Southgate's certificate application to the FERC in November 2018. The Final Environmental Impact Statement for the project was issued on February 14, 2020. In June 2020, the FERC issued the CPCN for the MVP Southgate; however, the FERC, while authorizing the project, directed the Office of Energy Projects not to issue a notice to proceed with construction until necessary federal permits are received for the MVP project and the Director of the Office of Energy Projects lifts the stop work order and authorizes the LLC to continue constructing the MVP. On August 11, 2020, the North Carolina Department of Environmental Quality (NCDEQ) denied Southgate's application for a Clean Water Act Section 401 Individual Water Quality Certification and Jordan Lake Riparian Buffer Authorization due to timing of the MVP project's completion. On March 11, 2021, the Fourth Circuit Court of Appeals, pursuant to an appeal filed by the LLC, vacated the NCDEQ's denial and remanded the matter to the NCDEQ for additional review. On April 29, 2021, the NCDEQ reissued its denial of Southgate's application. Based on the targeted full in-service date for the MVP and expectations regarding Southgate permit approval timing, the LLC is targeting the commencement of the MVP Southgate construction in 2022 and placing the MVP Southgate in-service during the spring of 2023.

Midstream has borrowing capacity of $41 million under its current credit facility, which matures in December 2022. As of September 30, 2021, $33.6 million had been utilized.  Effective November 1, 2021, the borrowing capacity under this credit facility was reduced to $33 million as $8 million of the outstanding balance was termed out in a separate unsecured promissory note.  See the Capital Resources and Liquidity section for more information. This credit facility will provide additional financing capacity for MVP funding; however, due to ongoing delays, additional financing will be required. Management is working with the Company's lending institutions to secure the necessary funding. If the legal and regulatory challenges, including any future challenges, are not resolved in a timely manner and/or restrictions are imposed that impact future construction, the cost of the MVP and Midstream's capital contributions may increase above current projections.

Regulatory

On January 24, 2020, the SCC issued its final general rate case order awarding Roanoke Gas an annualized non-gas rate increase of $7.25 million and providing for a 9.44% return on equity and directing the write-off of $317,000 of ESAC assets not subject to recovery under the approved rates. Rates authorized by the SCC's final order required the Company to issue customers $3.8 million in rate refunds, which was completed in March 2020.

The final order also excluded from current rates a return on the investment of two interconnect stations with the MVP, but provided Roanoke Gas with the ability to defer the related financing costs of those investments for possible future recovery. As a result, the Company began recognizing AFUDC during the second quarter of fiscal 2020 to capitalize both the equity and debt financing costs incurred during the construction phases. During the first quarter of 2021, Roanoke Gas recognized a total of $55,981 in AFUDC, $41,978 and $14,003 of equity and debt carrying costs, respectively. Beginning January 2021, Roanoke Gas temporarily ceased recording AFUDC on its related MVP interconnect construction projects until such time as construction activities resume. 

The service disconnection moratorium under which the Company has been operating since March 16, 2020, expired August 30, 2021. During the moratorium, utilities were prohibited from disconnecting residential customers for non-payment of their natural gas service and from assessing late payment fees; therefore, residential customers that ordinarily would have been disconnected for non-payment continued incurring charges for gas service. As a result, the Company’s arrearage balances are at historically high levels, which has resulted in a higher potential for bad debt write-offs. 

In December 2020, Roanoke Gas received $403,000 in CARES Act funds to assist customers with growing past due balances. Based on guidance provided by the SCC, the Company was able to apply the full amount to eligible customer accounts during the second and third fiscal quarters. On October 28, 2021, Roanoke Gas received notification from the SCC that its application for ARPA funds has been approved.  According to the communication, the Company will receive $858,556 based on arrearage balances as of August 31, 2021.  The pending receipt of these funds were considered in the valuation of the estimated allowance for  uncollectibles as of September 30, 2021. 

In April 2020, the SCC issued an order allowing regulated utilities in Virginia to defer certain incremental, prudently incurred costs associated with the COVID-19 pandemic and to apply for recovery at a future date. Roanoke Gas deferred certain COVID-19 related costs throughout fiscal 2021.  Based on Roanoke Gas's preliminary earnings test for the period ended September 30, 2021, fiscal 2021 earnings exceeded the mid-point of the authorized return resulting in the COVID-19 related costs being expensed during the fourth quarter.

Roanoke Gas continues to recover the costs of its infrastructure replacement program through its SAVE Rider. In May 2021, the Company filed its most recent SAVE application with the SCC to update the SAVE Plan and Rider for the period October 2021 through September 2022. In its application, Roanoke Gas requested to continue to recover the costs of the replacement of pre-1973 plastic pipe. In addition, the Company requested to include the replacement of certain regulator stations and pre-1971 coated steel pipe as qualifying SAVE projects. The updated SAVE Rider is designed to collect approximately $3.45 million in annual revenues, an increase of approximately $1.1 million from the existing SAVE Rider rates.  The Company received a final order on August 25, 2021 in which the SCC approved the Company’s requested revenue requirement.

Critical Accounting Policies and Estimates

The consolidated financial statements of Resources are prepared in accordance with accounting principles generally accepted in the United States of America. 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 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 FASB ASC No. 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. The write-downs of the COVID asset and ESAC assets are consistent with the provisions of ASC No 980.

Revenue recognition - Regulated utility sales and transportation revenues are based upon rates approved by the SCC. The non-gas cost component of rates may not be changed without a formal rate application and corresponding authorization by the SCC in the form of a Commission order; however, the gas cost component of rates is adjusted quarterly, or more frequently if necessary, through the PGA mechanism. When the Company files a request for a non-gas rate increase, the SCC may allow the Company to place such rates into effect subject to refund pending a final order. Under these circumstances, the Company estimates the amount of increase it anticipates will be approved based on the best available information.

The Company also bills customers through a SAVE Rider that provides a mechanism to recover on a prospective basis the costs associated with the Company’s expected investment related to the replacement of natural gas distribution pipe and other qualifying projects. As authorized by the SCC, the Company adjusts billed revenues monthly through the application of the WNA model. As the Company's non-gas rates are established based on the 30-year temperature average, monthly fluctuations in temperature from the 30-year average could result in the recognition of more or less revenue than for what the non-gas rates were designed. The WNA authorizes the Company to adjust monthly revenues for the effects of variation in weather from the 30-year average with a corresponding entry to a WNA receivable or payable. At the end of each WNA year, the Company refunds excess revenue collected for weather that was colder than the 30-year average or bills customers for revenue short-fall resulting from weather that was warmer than normal. As required under the provisions of ASC No. 980, the Company recognizes billed revenue related to SAVE projects and from the WNA to the extent such revenues have been earned under the provisions approved by the SCC.

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 $1,191,227 and $1,041,518 as of September 30, 2021 and 2020, respectively.

The Company adopted ASU 2014-09, Revenue from Contracts with Customers, and subsequent guidance and amendments effective October 1, 2018. The adoption of the ASU did not have a significant effect on the Company's results of operations, financial position or cash flows as the new guidance resulted in essentially no change in the manner and timing in which the Company recognizes revenues. The primary operation of the Company is the sale and/or delivery of natural gas to customers (the performance obligation) based on SCC approved tariff rates (the transaction price). The Company recognizes revenue through billed and unbilled customer usage as natural gas is delivered. The Company also recognizes revenue through ARPs, including the WNA.

Allowance for Doubtful Accounts - The Company evaluates the collectability of its accounts receivable balances based upon a variety of factors including loss history, level of delinquent account balances, collections on previously written off accounts and general economic conditions. The historical model used in valuing reserve for bad debts has been consistently applied over recent years and has produced reasonable estimates for valuing the potential loss on customer accounts receivable. With the arrival of COVID-19 and the unprecedented widespread impact deriving from the pandemic, including the 17 month disconnection moratorium, the estimation of the Company's bad debt reserves has become more subjective with greater reliance on qualitative assessments and judgment rather than historical patterns and tendencies.  Furthermore, the federal government has made funds available through the CARES Act and ARPA, which have materially reduced the expected uncollectable balances as of September 30, 2021.  Accordingly, based on management's evaluation, the total bad debt reserves were estimated at $242,010 as of September 30, 2021.    

The Company is committed to working with its customers during these difficult times by providing extended payment terms and assisting customers in finding other sources of financial aid.  With rising natural gas prices and lingering economic effects from the moratorium and COVID, bad debt concerns will continue into fiscal 2022.

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 9 to 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. 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 2.73% and 2.70%, respectively, for valuing its pension plan liability and postretirement plan liability at September 30, 2021. These discount rates represent an increase from the 2.47% and 2.44% rates used for valuing the corresponding liabilities at September 30, 2020. The increase in discount rates corresponds to the inflationary pressures and current market conditions as the economy emerges from the impact of COVID. The yield on the 30-year Treasury increased from 1.46% last year to 2.08% at September 30, 2021. Corporate bond rates experienced a smaller increase as credit spreads appear to 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 generational mortality improvements using Projection Scale MP-2020 for the current year valuation.

Management has continued to focus on reducing risk in the Company's defined benefit plans with a greater emphasis on pension plan risk. In 2016, the Company offered a one-time, lump-sum payout of the pension benefit to vested former employees who were not receiving payments under the plan. In 2017, the Company implemented a "soft freeze" to the pension plan whereby employees hired on or after January 1, 2017 would not be eligible to participate. Employees hired prior to that date continue to accrue benefits based on compensation and years of service. This "soft freeze" mirrored the strategy in 2000 when the Company implemented a similar freeze in its postretirement plan. In October 2020, the Company again offered a one-time lump-sum payout option of deferred pension benefits to those vested terminated employees not currently receiving pension benefits. Lump sum payments of $717,197 were made to those participants that elected this option and reduced corresponding pension liabilities by approximately $965,000.  Each of these strategies have served to limit liability growth and reduce volatility.

The Company also has focused on its asset investment strategy. A combination of funding strategy and solid investment returns have allowed pension plan assets to increase by $10.7 million over the last three years, while liabilities increased by $8.8 million during the same period primarily due to a decline in the discount rate for determining the liability from 4.11% at September 30, 2018 to 2.73% at September 30, 2021.  As of September 30, 2021, the pension plan is 103% funded compared to 94% funded in the prior year. Future pension liability growth associated with participant service and compensation is limited to employees hired prior to the freeze. With the soft freeze of the pension plan, the portion of the liability attributable to active eligible employees continuing to accrue benefits has declined from 56% of the liability as of the date of the soft freeze to 39% in fiscal 2021.  The remaining 61% of the 2021 liability is set subject to variability due to changes in the discount rate and mortality adjustments.  Since January 2017 when the pension plan froze access to new employees, the asset allocation has transitioned from a 60% equity and  40% fixed income allocation to a 30% equity and 70% fixed income allocation.  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 for benefits to be paid.  This synchronization of 70% of the pension assets with the pension liabilities will reduce volatility in the funded status of the plan as well as the corresponding expense.  The 30% 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 not made a change in investment allocation for the postretirement plan assets as increasing medical and insurance costs warrant the need for a continued higher allocation to equities for future plan asset growth potential. The postretirement plan assets increased by $2.9 million and liabilities increased by $0.6 million over the last three-year period.  As the number of participants in the postretirement plan continue to decline through attrition, 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:

The Company annually evaluates the returns on its targeted investment allocation model as well as the overall asset allocation of its benefit plans. Understanding the volatility in the markets, the Company reviews both plans' potential long-term rate of return with its investment advisors to determine the rates used in each plan's actuarial assumptions. Under the current allocation model for the pension plan, management lowered the long-term rate of return assumption from 5.40% in fiscal 2021 to 4.75% in fiscal 2022 based on the change in the current equity allocation of the pension plan assets and the lower rate of return expected on the fixed income investments. The long-term rate of return was virtually unchanged for the postretirement plan at 4.25% as the asset allocation remains at 50% equity and 50% fixed income. Management will continue to re-evaluate the return assumptions and asset allocation and adjust both as market conditions warrant.

Management estimates that, under the current provisions regarding defined benefit pension plans, the Company will have no minimum funding requirements next year. However, the Company currently expects to contribute approximately $500,000 to its pension plan and $400,000 to its postretirement plan in fiscal 2022. 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.

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.

Derivatives - The Company may hedge certain risks incurred in its operation through the use of derivative instruments. The Company applies the requirements of FASB ASC No. 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 three interest-rate swaps outstanding at September 30, 2021 related to its three variable rate notes and two interest-rate swaps associated with delayed draw notes to be funded subsequent to fiscal 2021. See Note 7 to the consolidated financial statements for additional information regarding the swaps.

Item 7A.    Quantitative and Qualitative Disclosures About Market Risk.

Not applicable.

Item 8.    Financial Statements and Supplementary Data.

RGC Resources, Inc. and Subsidiaries

Consolidated Financial Statements

for the Years Ended September 30, 2021 and 2020

and Report of Independent

Registered Public Accounting Firm

RGC RESOURCES, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

RGC Resources, Inc.

Roanoke, Virginia

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, 2021 and 2020, and the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the years in the two-year period ended September 30, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the years in the two-year period ended September 30, 2021, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public 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 Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relate 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 consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Valuation of Equity Method Investment in Mountain Valley Pipeline, LLC (“MVP”)

Description of the matter

As of September 30, 2021, the Company has investments in unconsolidated affiliates of $64.9 million. The majority of this amount, $64.5 million consists of an equity method investment in the Mountain Valley Pipeline, LLC.  As discussed in Note 5 to the consolidated financial statements, the Company accounts for its investment in MVP under the equity method because it has the ability to exercise significant influence, but not control, over MVP’s operating and financial policies. The Company reviews the carrying value of its investments in unconsolidated entities for impairment whenever events or changes in circumstances indicate a decline in value. When there is evidence of loss in value that is other than temporary, the Company compares the investment's carrying value to its estimated fair value to determine whether impairment has occurred.  The Company evaluated its investment in MVP for impairment and determined the fair value exceeded the carrying value at September 30, 2021. Accordingly, no impairment losses were recorded. The Company contracted a third party valuation specialist to perform a valuation of this investment as of September 30, 2021.

Auditing management’s evaluation of impairment of the equity investment in MVP was complex due to significant judgment required to determine fair value of the investment. In particular, fair value estimates of the investment in MVP were sensitive to significant assumptions, including discounted cash flows. These assumptions could be affected by factors such as adverse macroeconomic conditions or permit and litigation matters impacting MVP. Audit procedures performed to evaluate the reasonableness of management’s estimates required a high degree of auditor judgement and increased effort.

How We Addressed the Matter in our Audit

We obtained an understanding of the Company’s equity method investment impairment evaluation process and significant assumptions described above.  In order to test this process, we performed audit procedures regarding methodologies utilized, significant assumptions, and underlying data in the analyses for completeness and accuracy. We involved valuation specialists from our firm to assist in reviewing valuation methodology and testing the discount rate assumption.

Audit procedures related to discounted future cash flows included, among others, procedures to evaluate cash flows considered in the valuation. We performed procedures to assess management’s consideration of potential changes in legal or regulatory trends and how such developments could impact significant assumptions that influence the in-service dates or viability of the project, and evaluated the sufficiency of the Company’s financial statement disclosures.

CERTIFIED PUBLIC ACCOUNTANTS

We have served as the Company's auditor since 2006.

Blacksburg, Virginia

December 2, 2021

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

AS OF September 30, 2021 AND 2020

(Continued)

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

AS OF September 30, 2021 AND 2020

See notes to consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

YEARS ENDED September 30, 2021 AND 2020

See notes to consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

YEARS ENDED September 30, 2021 AND 2020

See notes to consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

YEARS ENDED September 30, 2021 AND 2020

See notes to consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

YEARS ENDED September 30, 2021 AND 2020

See notes to consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED September 30, 2021 AND 2020

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, Midstream and Diversified Energy. Roanoke Gas is a natural gas utility, which distributes and sells natural gas to approximately 62,600 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 Mountain Valley Pipeline project. Diversified Energy is inactive.

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 FASB ASC No. 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 FASB ASC No. 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 FASB ASC No. 980 no longer applied.

Regulatory assets and liabilities included in the Company’s consolidated balance sheets as of September 30, 2021 and 2020 are as follows: 

Amortization of $84,315 and $1,106,511 of regulatory assets for the years ended September 30, 2021 and  2020, respectively, is included in operations and maintenance expense on the consolidated statements of income. See Note 3 for more information.

As of September 30, 2021, the Company had regulatory assets in the amount of $12,812,401 on which the Company did not earn a return during the recovery period.

Utility Plant and Depreciation—Utility plant 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 they significantly improve or extend the original expected useful life of an asset. Expenditures for maintenance, repairs, and minor renewals and betterments are expensed as incurred. The original cost of depreciable property retired is removed from utility plant 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 plant is composed of the following major classes of assets:

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 last depreciation study was completed and approved by the SCC staff in fiscal 2019. The Company will be required to complete a new depreciation study no later than fiscal 2024. The composite weighted-average depreciation rate was 3.28% and 3.30% for the years ended September 30, 2021 and 2020, respectively. 

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 FASB ASC No. 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.

In fiscal 2020, Roanoke Gas implemented the application of AFUDC related to infrastructure investments associated with two gate stations that will interconnect with the MVP. This treatment allows capitalizing both the equity and debt financing costs during the construction phases. For the years ended September 30, 2021, and 2020, the Company capitalized $14,003 and $81,629 of debt financing costs and $41,978 and $248,579 of equity financing costs, respectively, thereby affecting the interest expense and other income, net lines of the related consolidated statements of income. See Note 3 for further information.

Asset Retirement Obligations—FASB ASC No. 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 legal obligations related to purging and capping its distribution mains and services upon retirement, although the timing of such retirements is uncertain.

The Company’s composite depreciation rates include a component to provide for the cost of retirement of assets. As a result, the Company accrues the estimated cost of retirement of its utility plant through depreciation expense and creates a corresponding regulatory liability. The costs of retirement considered in the development of the depreciation component include those costs associated with the legal liability. Therefore, the ARO is reclassified from the regulatory cost of retirement obligation. If the legal obligations were to exceed the regulatory liability provided for in the depreciation rates, the Company would establish a regulatory asset for such difference with the anticipation of future recovery through rates charged to customers.

The following is a summary of the AROs:

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. As of September 30, 2021, the Company did not have any bank deposits in excess of the FDIC insurance limits. 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 Doubtful Accounts—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.

Due to the impact of COVID-19 on businesses and individuals, customer delinquent and past due balances increased significantly over the last two years. The allowance for doubtful accounts disclosed below has been adjusted to reflect the impact of $859,000 in pending ARPA funds.  Without the ARPA and CARES Act funds, the allowance for doubtful accounts would have been more than $1 million as of September 30, 2021. See Notes 3 and 15 for additional information.

A reconciliation of changes in the allowance for doubtful accounts is as follows: 

Financing Receivables—Financing receivables represent a contractual right to receive money either on demand, or on fixed or determinable dates, and are recognized as assets on the entity’s balance sheet. Trade receivables, resulting from the sale of natural gas and other services to customers, are the Company's primary type of financing receivables. These receivables are short-term in nature with a provision for uncollectible balances included in the consolidated financial statements.

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 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, 2021 and 2020 were $1,191,227 and $1,041,518, 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—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. 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 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:

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. See fair value disclosures below and in Notes 9 and 13.

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 accounted for on a net basis and therefore are not included as revenues in the Company’s consolidated income statements.

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 dilutive potential common shares, respectively. Dilutive potential 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. A reconciliation of basic and diluted EPS is presented below: 

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 or amounted to more than 5% of total accounts receivable.

Roanoke Gas currently holds the only franchises and CPCNs to distribute natural gas in its service area. These franchises are effective through January 1, 2036. The Company's current CPCNs in Virginia are exclusive and are intended for perpetual duration.

Roanoke Gas is served directly by two primary pipelines that provide all of the natural gas supplied to the Company’s customers. Depending upon weather conditions and the level of customer demand, failure of one or both of these transmission pipelines could have a major adverse impact on the Company.

Derivative and Hedging Activities—FASB ASC No. 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.

The Company historically 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, 2021 and 2020, the Company had no outstanding derivative instruments for the purchase of natural gas.

The Company has five interest rate swaps associated with its variable rate debt. Roanoke Gas has a swap on its $7 million term note that effectively converts the variable interest rate into a 2.30% fixed interest rate. During fiscal 2021, Roanoke Gas entered into two delayed draw 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. Proceeds associated with the delayed draw notes were not received during the current fiscal year; therefore, the swaps associated with those notes were not effective during fiscal 2021. Midstream has two variable-rate term notes in the amount of $14 million and $10 million with corresponding swap agreements to convert the variable interest rates into fixed rates of 3.24% and 3.14%, respectively. All swaps qualify as a cash flow hedge with changes in fair value reported in other comprehensive income. Any cash flows from interest rate swaps are classified as interest expense. No portion of the swaps were deemed ineffective during the period.

See Notes 7 and 13 for additional information on the swaps and fair value.

Non-Cash Activity — A non-cash decrease in unconsolidated affiliate and corresponding decrease in capital contributions payable of $371,800 and $2,512,387 occurred for the fiscal years ended September 30, 2021 and 2020, respectively.

Other Comprehensive Income (Loss)—A summary of other comprehensive income is provided below:

The amortization of actuarial gains or losses are included as a component of net periodic pension and postretirement benefit costs under other income, net.

Composition of AOCI: 

Recently Adopted Accounting Standards

In February 2016, the FASB issued ASU 2016-02, Leases. This ASU leaves the accounting for leases mostly unchanged for lessors, with the exception of targeted improvements for consistency; however, the new guidance requires lessees to recognize assets and liabilities for leases with terms of more than 12 months. The ASU also revises the definition of a lease as a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment for a period of time in exchange for consideration. Under prior GAAP, the presentation and cash flows arising from a lease by a lessee primarily depended on its classification as a finance or operating lease. The new ASU requires both types of leases to be recognized on the balance sheet. In addition, the new guidance includes quantitative and qualitative disclosure requirements to aid financial statement users in better understanding the amount, timing and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU 2018-01, which provides a practical expedient that allows entities the option of not evaluating existing land easements under the new lease standard for those easements that were entered into prior to adoption. New or modified land easements will require evaluation on a prospective basis. The new guidance is effective for the Company for the annual reporting period ending September 30, 2021 and interim periods within that annual period.

The Company adopted ASU 2016-02 and related guidance effective October 1, 2019. At the time of adoption, the Company had one operating lease. This lease, which was renewed in fiscal 2021, calls for monthly payments in the amount of $1,100 and is set to expire in September 2025. As the value of this lease obligation was determined to be de minimis and the Company has not entered into any additional lease obligations, this new guidance does not have a material effect on the Company's financial position, results of operations or cash flows.

In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging: Targeted Improvements to Accounting For Hedging Activities. The ASU is meant to simplify recognition and presentation guidance in an effort to improve financial reporting of cash flow and fair value hedging relationships to better portray the economic results of an entity's risk management activities. This is achieved through changes to both the designation and measurement guidance for qualifying hedging relationships, as well as changes to the presentation of hedge results. The Company adopted the new guidance effective October 1, 2019. As the Company currently has only cash flow hedges and no portion of these hedges were deemed ineffective during the periods presented, this new guidance does not have a material effect on the Company's financial position, results of operations or cash flows.

In August 2018, the FASB issued ASU 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs incurred in a Cloud Computing Arrangement that is a Service Contract. This ASU reduces the complexity of accounting for costs of implementing a cloud computing service arrangement and aligns the following requirements to capitalize implementation costs: 1) those incurred in a hosting arrangement that is a service contract, and 2) those incurred to develop or obtain internal-use software, including hosting arrangements that include an internal software license. The Company adopted the new guidance effective October 1, 2019. The new guidance did not have a material effect on the Company's consolidated financial statements.

In August 2018, the FASB issued ASU 2018-14, Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20) - Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans. This ASU modifies disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The Company adopted the new guidance effective October 1, 2020. The new guidance did not have a material effect on the Company's consolidated financial statements.

Recently Issued Accounting Standards

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848) - Facilitation of the Effects of Reference Rate Reform on Financial Reporting. In combination with 2021-01, the ASU provides temporary optional guidance to ease the potential burden in accounting for and recognizing the effects of reference rate change on financial reporting. The new guidance applies specifically to contracts and hedging relationships that reference LIBOR, or any other referenced rate that is expected to be discontinued due to reference rate reform. The new guidance is effective for the Company through December 31, 2022. The Intercontinental Exchange (ICE) Benchmark Administration, the administrator for LIBOR and other inter-bank offered rates, announced that the LIBOR rates for one-day, one-month, six-month and one-year will cease publication in  June 2023 and that no new financial contracts  may use LIBOR after  December 31, 2021. Currently, all of the Company's LIBOR based financial contracts are based on the one-month LIBOR rate. None of the holders of these financial contracts have indicated when a transition from LIBOR will occur. Accordingly, the Company does not anticipate adopting this guidance until fiscal 2022. The new guidance could result in a significant impact on the Company's financial position, results of operations, and cash flows when the reference rate is changed for related contracts.

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.

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: