This report contains forward-looking statements that relate to future transactions, events or expectations. In addition, RGC Resources Inc. (“Resources” or the “Company”) 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.
Resources Inc. ("Resources" or the "Company") was incorporated in the stateCommonwealth of Virginia on July 31, 1998 for the primary purpose of becoming the holding company for Roanoke Gas Company (“Roanoke Gas”) and, its subsidiaries. Effectiveeffective July 1, 1999, Roanoke Gas and its subsidiaries were reorganized into the Resources holding company structure. Resources is currently composed of the following subsidiaries: Roanoke Gas, Midstream and Diversified Energy Company and RGC Midstream, LLC.
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%1% of consolidated revenues.
In July 2015, the Company formed RGC Midstream LLC, a limited liability company established for the purpose of becoming a 1% investor in Mountain Valley Pipeline, LLC. Mountain Valley Pipeline,The LLC was created for the purpose of constructing ato construct and operate interstate natural gas pipeline in West Virginia and Virginia.pipelines. Additional information regarding this investment is provided under Note 45 of the Company's annual consolidated financial statements and under the Equity Investment in Mountain Valley Pipeline section of Item 7.
Diversified Energy Companyis currently has no active operations.
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 decatherms)DTHs), revenues and margin as a percentage of the total for each category:
| 2017 | ||||||||||||||
| Customers | Volume | Revenue | Margin | |||||||||||
| Residential | 91.2 | % | 37 | % | 57 | % | 61 | % | ||||||
| Commercial | 8.7 | % | 31 | % | 33 | % | 25 | % | ||||||
| Industrial | 0.1 | % | 32 | % | 7 | % | 10 | % | ||||||
| Other Utility | 0.0 | % | 0 | % | 1 | % | 2 | % | ||||||
| Other Non-Utility | 0.0 | % | 0 | % | 2 | % | 2 | % | ||||||
| Total Percent | 100.0 | % | 100 | % | 100 | % | 100 | % | ||||||
| Total Value | 59,847 | 8,562,582 | $ | 62,296,870 | $ | 32,809,157 | ||||||||
| 2016 | ||||||||||||||
| Customers | Volume | Revenue | Margin | |||||||||||
| Residential | 91.2 | % | 38 | % | 57 | % | 60 | % | ||||||
| Commercial | 8.7 | % | 31 | % | 33 | % | 25 | % | ||||||
| Industrial | 0.1 | % | 31 | % | 7 | % | 11 | % | ||||||
| Other Utility | 0.0 | % | 0 | % | 1 | % | 2 | % | ||||||
| Other Non-Utility | 0.0 | % | 0 | % | 2 | % | 2 | % | ||||||
| Total Percent | 100.0 | % | 100 | % | 100 | % | 100 | % | ||||||
| Total Value | 59,635 | 8,842,605 | $ | 59,063,291 | $ | 31,564,914 | ||||||||
| 2015 | ||||||||||||||
| Customers | Volume | Revenue | Margin | |||||||||||
| Residential | 91.2 | % | 40 | % | 58 | % | 58 | % | ||||||
| Commercial | 8.7 | % | 30 | % | 33 | % | 26 | % | ||||||
| Industrial | 0.1 | % | 30 | % | 6 | % | 11 | % | ||||||
| Other Utility | 0.0 | % | 0 | % | 1 | % | 3 | % | ||||||
| Other Non-Utility | 0.0 | % | 0 | % | 2 | % | 2 | % | ||||||
| Total Percent | 100.0 | % | 100 | % | 100 | % | 100 | % | ||||||
| Total Value | 59,080 | 9,875,007 | $ | 68,189,607 | $ | 30,206,433 | ||||||||
2022 | ||||||||||||||||
Customers | Volume | Revenue | Margin | |||||||||||||
Residential | 91.3 | % | 35 | % | 57 | % | 63 | % | ||||||||
Commercial | 8.6 | % | 29 | % | 35 | % | 24 | % | ||||||||
Industrial | 0.1 | % | 36 | % | 7 | % | 11 | % | ||||||||
Other Utility | 0.0 | % | 0 | % | 1 | % | 2 | % | ||||||||
Other Non-Utility | 0.0 | % | 0 | % | 0 | % | 0 | % | ||||||||
Total Percent | 100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | ||||||||
Total Value | 62,001 | 10,325,336 | $ | 84,165,222 | $ | 41,640,041 | ||||||||||
2021 | ||||||||||||||||
Customers | Volume | Revenue | Margin | |||||||||||||
Residential | 91.3 | % | 37 | % | 58 | % | 63 | % | ||||||||
Commercial | 8.6 | % | 31 | % | 34 | % | 25 | % | ||||||||
Industrial | 0.1 | % | 32 | % | 7 | % | 11 | % | ||||||||
Other Utility | 0.0 | % | 0 | % | 1 | % | 1 | % | ||||||||
Other Non-Utility | 0.0 | % | 0 | % | 0 | % | 0 | % | ||||||||
Total Percent | 100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | ||||||||
Total Value | 62,623 | 9,909,529 | $ | 75,174,779 | $ | 39,969,380 | ||||||||||
Roanoke Gas’ regulated natural gas distribution business accounted for approximately 98%more than 99% of Resources total revenues for fiscal years ending September 30, 2017, 20162022 and 2015.2021. The tables above indicatesindicate that residential customers represent over 91% of the Company’s customer total; however, they represent less than 50%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 approximately 7% of total revenues, even thoughless than 10%, although they represent 32%more than 30% of total natural gas deliveriesvolumes and approximately 11% of margin for the year ended September 30, 2017 and approximately 10% to 11% of gross margin for each of the years presented.
The Company’s revenues are affected by changes in gas costs, as well as by changes in consumption volume due to weather and economic conditions and changes in the non gasnon-gas portion of customer billing rates. Increases or decreases in the cost of natural gas are passed on to customers through the purchased gas adjustmentPGA mechanism as explained in further detail in Note 1 of the Company’s annual consolidated financial statements. Significant increases in gas costs may cause customers to conserve or, in the case of industrial customers, to switch to alternative energy sources.
The Company’s residential and commercial sales are primarily seasonal and temperature-sensitivesubject to temperature sensitivity as the majority of the gas sold by Roanoke Gas to these customers is used for heating. For the fiscal year ended September 30, 2017,2022, approximately 65%62% of the Company’s total DTH of natural gas deliveries and 73%74% of the residential and commercial deliveries were made in the five-month period of November through March. These percentages are comparable to the prior year but lower than fiscal 2015 due to lower volumes attributable to a much warmer heating season in fiscal 2016 and 2017. Total natural gas deliveries were 8.6 million DTH, 8.8 million DTH and 9.9 million DTH in fiscal 2017, 2016 and 2015, respectively.
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 approximately 60%more than 65% of the Company’s required gas supply, whilewith East Tennessee deliversdelivering the balance of the Company’s requirements.balance. The rates paid for interstate natural gas transportation and storage services purchased from the interstate pipeline companies are established by tariffs approved by the Federal Energy Regulatory Commission ("FERC"). These tariffs contain flexible pricing provisions, which, in some instances, authorize these transporters to reduce rates and charges to meet price competition.FERC. The current pipeline and storage contracts expire at various times from 20182023 to 2027.2028. The Company anticipates being able to renew these contracts or enter into other contracts to meet customers’ continuedexisting demand for natural gas.
The Company manages its pipeline contracts and liquefied natural gas storage (“LNG”)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 underfrom the current interstate pipelines is 78,606 DTH per day. The LNG facility which is capable of storing up to 200,000 DTH of natural gas in a liquid state for use during peak demand, has the capability of providing an additional 27,000 DTH per day.demand. Combined, the pipelines and LNG facility canmay provide more than 105,000up 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
. TheThe Company uses summer storage programs to supplement heating season gas supply requirements during the winter months. During the summer months, the Company injects gas into its LNG facility. In addition, therequirements. The Company has contracted for 2.4 million DTH of storage capacity from Columbia, Tennessee Gas Pipeline and Saltville Gas Storage Company, LLC for a combined total of more than 2.4 million DTH of storage capacity.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 certificates of public convenience and necessityCPCNs 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 recently renewed for a 20-year term, of 20 years and willset to expire December 31, 2035.
Management anticipates that the Company will be able to renew all of its franchises when they expire. Thereprior to their current expiration date; however, there can be no assurance however, 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. Certificates of public convenience and necessity,CPCNs, issued by the Virginia State Corporation Commission (the “SCC”),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 driver being price in most instances.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, a plentiful supplyIncreased demand, including off-shore LNG shipments, and lower storage levels are placing upward pressure on the price of natural gas, mostly duegas.
Competition from renewable energy sources such as solar and wind is likely to improved drilling and extraction processes in shale formations, has served to maintain prices at lower levels. Theincrease 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 its product. New construction activitynatural gas. Growth in residential and commercial service has remainedbeen steady over the last few years andas the Company continues to grow its customer base through a combination of extending distribution service to new construction and converting existing alternativeother energy source 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 and theTransportation'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, 2017,2022, Resources had 10696 full-time employees and 109 total employees. As of that date, 30 employees, or 28% of the Company’s full-time employees, belonged toDuring fiscal 2022, Roanoke Gas notified the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial International Union, Local No. 515 and were represented under a collective bargaining(the "Union") representing Company employees of its intent to withdraw recognition of the Union upon expiration of the current agreement. The union has been in place atEffective August 1, 2022, the Company since 1952. The current collective bargaining agreement will expirebetween the Union and Roanoke Gas expired and the Union, due to the sustained lack of majority support by bargaining unit members, accepted the Company's withdrawal of recognition and disclaimed its interest in serving as the exclusive collective-bargaining representative of employees of Roanoke Gas. Prior to the expiration of the contract, 16 employees were represented by the Union. Employees had been represented by a union since 1952.
The Company’s business strategy and ability to serve customers relies on July 31, 2020. Management maintains an amicable relationship withemploying talented professionals and attracting, training, developing and retaining a skilled workforce. This is particularly relevant as the union.
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 thePlease 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 financial:
OPERATIONAL RISKS
Availability of adequatesufficient 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 and, if sufficiently frequentrestoration. Frequent or prolonged failure could lead customers to turnswitch to alternative energy sources.
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 policies with financially sound carrierscoverage to protect against many of these risks. IfHowever, 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.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.
Volatility in the price and availability of natural gas.
Natural gas purchases represent the single largest expense of the Company. Increasing demand from other areas, including electricity generation, combined with other factors, 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.
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.
Inability to attract and retain professional and technical employees.
The ability to implement the Company’s business strategy and serve customers is dependent upon employing talented professionals and attracting, training, developing and retaining a skilled workforce. As the Company expects key personnel to retire over the next several years, 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.
Increased dependence on technology may hinder the Company’s business operations and adversely affect its financial condition and results of operations if such technologies fail.
Over the last several years, the Company has implemented or acquired a variety of technological tools including both Company-owned information technology and technological services provided by outside parties. These tools and systems support critical functions including, scheduling and dispatching of service technicians, automated meter reading systems, customer care and billing, operational plant logistics, and external financial reporting. The failure of these or other similarly important technologies, or the Company’s inability to have these technologies supported, updated, expanded, or integrated into other technologies, could hinder its business operations and adversely impact its financial condition and results of operations. Although the Company has, when possible, developed alternative sources of technology and built redundancy into its computer networks and tools, there can be no assurance that these efforts would protect against all potential issues related to the loss of any such technologies.
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 primarily 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.
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.
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 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 or provide incentives to customers to utilize alternative energy sources not associated with fossil fuels.
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. During periods of enhanced inflationary pressure or the incurrence of significant additional costs, if the SCC did not timely authorize rates that provided for the recovery of such costs including a reasonable rate of return on investment in natural gas distribution facilities, earnings could be negatively impacted.
Furthermore, issuance of debt and equity by Roanoke Gas is also subject to SCC regulation and approval. Delays or lack of approvals could inhibit the ability to access capital markets and negatively impact liquidity or earnings.
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.
On January 25, 2022, the Fourth Circuit vacated and remanded on specific issues certain permits issued by the Bureau of Land Management and the U.S. Forest Service to the LLC in respect to the Jefferson National Forest. On February 3, 2022, the Fourth Circuit vacated and remanded on specific issues the Biological Opinion and Incidental Take Statement issued by the U.S. Fish and Wildlife Service for MVP. Due to the greater uncertainty of the ultimate completion and commercial operation of MVP, the in-service target of summer 2022 was withdrawn. Additionally, the Company, after assessing the fair value of its investment in the project, using probability-weighted scenarios of ultimate completion and commercial operation, including discounted future cash flows, concluded that an other-than-temporary decline in fair value existed as of February 22, 2022. The resulting $39.8 million pre-tax impairment loss was recorded in the Company’s fiscal 2022 second quarter financial statements.
The Company re-assesses its equity investment at least quarterly. In its most recent assessment, due to increasing uncertainty concerning the ultimate completion of the pipeline, and the decision by the LLC's managing partner to record a further impairment of its investment in the joint venture, the Company recorded an additional $15.3 million pre-tax impairment concluding an other-than-temporary decline in fair value existed as of September 30, 2022. After the subsequent impairment loss, recorded in the Company's fiscal fourth quarter, the total pre-tax loss totaled $55.1 million for the year ended September 30, 2022.
Future circumstances, including but not limited to significant construction delays, further denials of necessary permits and approvals, changes in the probability of ultimate completion, changes in future cash flow assumptions or changes in the discount rate could lead to further and possibly full impairment of the Company's investment in the LLC.
The success of the Company's investment in Mountain Valley Pipeline,the LLC (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, the timely state and federal approvals and resolving legal challenges to same and completing the construction of the pipeline within the targeted time frame and budget.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 MVP has been hindered by several legal and regulatory obstacles as the Fourth Circuit, FERC and other governmental agencies have vacated certain agency actions and 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. In addition there are also numerous risks facingto needing to address the LLC over time, which in turn could adverselymatters referenced above regarding the Jefferson National Forest and Biological Opinion and Incidental Take Statement, other regulatory and legal matters continue to affect the Company's earningsproject.
Ongoing obstacles as discussed above have in the past caused and financial performance through its 1% investment. The LLC's ability to completenew future obstacles may cause delays in construction, of, and capital improvement to, facilities on schedulemay further result in significantly higher projected costs and within budget may be adversely affected by escalating costsan extended targeted in-service date for materials and labor and regulatory compliance, inability to obtain or renew necessary licenses,
In addition, there are numerous risks facing the LLC, which can adversely affect the Company's earnings and prospects.financial performance through its investment. The LLC may face risks relatedLLC's ability to project siting, financing,retain contract crews to complete construction permitting, governmentalof 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 negotiationsuccessful completion of project development agreements that may impede its development and operating activities. The LLC must periodically apply for licenses and permits from various local, state, federal and other regulatory authorities and abide by their respective conditions.the pipeline. Should the LLC be unsuccessful in obtaining necessary licenses or permits on acceptable terms, should there be a delay in obtaining or renewing necessary licenses or permits or should regulatory authorities initiate any associated investigations or enforcement actions or impose related penalties or disallowances on the LLC,unable to adequately address these issues, the LLC’s business, financial condition, results of operations and prospects could be adversely affected, which could materially adversely affected.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 and other 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 that could resultresulting 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 sufficient.
The cost of operations and cash flows.
The Company provides health care benefits to its employees and covers a portion of the total cost. The cost of providing these and other benefits to active employees could significantly increase over time due to rapidly increasing health care inflation and any future legislative changes related funding of obligations.
The Company also provides certain post-retirement benefits. The costs of providing defined benefit pension and retiree medical plans are dependent on a number of factors such as the rates of return on plan assets, discount rates used in determining plan liabilities, the level of interest rates used to measure the required minimum funding levels of the plan, future government regulation, changes in life expectancy and required or voluntary contributions made to the plan. Changes in actuarial assumptions and differences between the assumptions and actual results, as well as a significant decline in the value of investments that fund these plans, if not offset or mitigated by a decline in plan liabilities, could increase the expense of these plans and require significant
Obligations for income taxes that may arise from examinations by taxing authorities.
The Company is subject to domestic income taxes as prescribed by the laws of the United States. Significant judgments are required in determining the provisions for income taxes. In preparing its tax provisions and returns, the Company must make calculations and assumptions regarding tax treatment of various transactions including the applicability of tax credits. The Company’s tax returns are subject to examination by the IRS and state tax authorities. Although the Company utilizes the assistance of tax professionals in the preparation of its tax returns, there can be no assurance as to the outcome of these examinations. If the ultimate determination from an examination results in additional taxes above the amount reflected in its financial statements, the Company will record any additional income taxes as may be required including any interest and penalties that might result.
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, there has been significant upward movement in interest rates. Much of the Company's outstanding debt is comprised of fixed rate notes or have interest rate swaps in place. However, these higher interest rates will impact the Company through higher borrowing costs on Roanoke Gas' line-of-credit and Midstream's variable rate credit facility as well as any future borrowings by the Company.
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 anlower 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 default which,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 not cureda significant number of employees were to contract the virus or waived, could accelerate payment on outstanding debt obligations or cause prepayment penalties. In such an event,be quarantined, the Company may not be able to refinancecomplete key or repaycritical 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.
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, deductibles and exclusions. Insurance coverage for risks against which the Company and its indebtedness, pay dividendsindustry peers typically insure may not be offered in the future or have sufficient liquiditysuch policies may expand exclusions that limit the amount of coverage or remove certain risks completely as insured events. Furthermore, litigation awards continue to meet operatingincrease and capital expenditure requirements. Anythe limits of insurance may not keep pace accordingly. The proceeds received from any such acceleration would causeinsurance 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.
Public perception of the natural gas industry in general have had and could continue to have a negative effect on the Company's business and may increase the likelihood of governmental actions directed at the natural gas industry.
Public perception resulting from, among other things, climate change, gas and other hydrocarbon leaks, the explosive nature of natural gas, erosion and sedimentation issues, unpopular expansion projects, environmental justice concerns, and general concerns raised by activists about hydraulic fracturing and pipeline projects has led to, and may in our financial condition.the future lead to, increased regulatory scrutiny, which may, in turn, lead to new local, state and federal safety and environmental laws, regulations, guidelines, enforcement interpretations and/or adverse judicial rulings or regulatory action. As discussed under Investment in Mountain Valley Pipeline, LLC above, there are several pending challenges to certain aspects of the MVP that affect the project cost and completion timeline. Failure to resolve these challenges could further increase the cost of completing the pipeline, delay the in-service date or potentially result in the termination of the project.
Included in “Utility Plant”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 1,1351,168 miles of transmission and distribution pipeline with transmission and distribution plant representing more than 87%89% of the total investment in plant.utility property 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 eightsix 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 Botetourt Countyits service territory that has the capacity to store up to 220,000200,000 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.
The Company is not known to be a party to any pending legal proceedings.
Item 4.Mine Safety Disclosures.
Not applicable.
Market Information
Resources' common stock is listed on the NASDAQ Global Market under the trading symbol RGCO. Payment of dividends is within the discretion of the Board of Directors and depends on, among other factors, earnings, capital requirements, and the operating and financial condition of the Company.
| Range of Bid Prices | Cash Dividends | |||||||||||
| Year Ending September 30, 2017 | High | Low | Declared | |||||||||
| First Quarter | $ | 20.04 | $ | 15.81 | $ | 0.1450 | ||||||
| Second Quarter | 22.51 | 16.60 | 0.1450 | |||||||||
| Third Quarter | 31.99 | 21.00 | 0.1450 | |||||||||
| Fourth Quarter | 29.95 | 23.65 | 0.1450 | |||||||||
| Year Ending September 30, 2016 | ||||||||||||
| First Quarter | $ | 15.96 | $ | 13.37 | $ | 0.1350 | ||||||
| Second Quarter | 15.59 | 13.77 | 0.1350 | |||||||||
| Third Quarter | 17.33 | 14.30 | 0.1350 | |||||||||
| Fourth Quarter | 16.73 | 14.88 | 0.1350 | |||||||||
Range of Bid Prices | Cash Dividends | |||||||||||
Year Ending September 30, 2022 | High | Low | Declared | |||||||||
First Quarter | $ | 25.00 | $ | 21.32 | $ | 0.195 | ||||||
Second Quarter | 23.84 | 20.25 | 0.195 | |||||||||
Third Quarter | 22.00 | 18.01 | 0.195 | |||||||||
Fourth Quarter | 23.35 | 19.18 | 0.195 | |||||||||
Year Ending September 30, 2021 | ||||||||||||
First Quarter | $ | 27.40 | $ | 22.82 | $ | 0.185 | ||||||
Second Quarter | 25.60 | 22.08 | 0.185 | |||||||||
Third Quarter | 25.60 | 21.32 | 0.185 | |||||||||
Fourth Quarter | 26.02 | 22.33 | 0.185 | |||||||||
As of November 24, 2017,18, 2022, there were 1,159 992 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, 2017:
(a) | (b) | (c) | ||||||||||
Plan category | Number of securities to be issued upon exercise of outstanding options, warrants and rights | Weighted-average exercise price of outstanding options, warrants and rights | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) | |||||||||
Equity compensation plans approved by security holders | 34,500 | $ | 18.69 | 411,547 | ||||||||
Equity compensation plans not approved by security holders | — | — | — | |||||||||
Total | 34,500 | $ | 18.69 | 411,547 | ||||||||
| (a) | (b) | (c) | |||||||
| Plan category | Number of securities to be issued upon exercise of outstanding options, warrants and rights | Weighted-average exercise price of outstanding options, warrants and rights | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) | ||||||
| Equity compensation plans approved by security holders | 101,575 | $14.31 | 576,018 | ||||||
| Equity compensation plans not approved by security holders | — | — | — | ||||||
| Total | 101,575 | $14.31 | 576,018 | ||||||
| Year Ending September 30, | ||||||||||||||||||||
| 2017 | 2016 | 2015 | 2014 | 2013 | ||||||||||||||||
| Operating Revenues | $ | 62,296,870 | $ | 59,063,291 | $ | 68,189,607 | $ | 75,016,134 | $ | 63,205,666 | ||||||||||
| Gross Margin | 32,809,157 | 31,564,914 | 30,206,433 | 29,337,089 | 27,602,891 | |||||||||||||||
| Operating Income | 11,666,309 | 11,212,092 | 10,006,192 | 9,681,868 | 8,795,055 | |||||||||||||||
| Net Income | 6,232,865 | 5,806,866 | 5,094,415 | 4,708,440 | 4,262,052 | |||||||||||||||
Basic Earnings Per Share (1) | $ | 0.86 | $ | 0.81 | $ | 0.72 | $ | 0.67 | $ | 0.60 | ||||||||||
Cash Dividends Declared Per Share (1) | $ | 0.58 | $ | 0.54 | $ | 0.51 | $ | 0.49 | $ | 1.15 | ||||||||||
Book Value Per Share (1) | $ | 8.29 | $ | 7.75 | $ | 7.43 | $ | 7.35 | $ | 7.01 | ||||||||||
Average Shares Outstanding (1) | 7,218,686 | 7,149,906 | 7,092,315 | 7,073,218 | 7,048,091 | |||||||||||||||
| Total Assets | $ | 183,135,071 | $ | 165,552,849 | $ | 145,847,194 | $ | 137,423,321 | $ | 121,658,797 | ||||||||||
| Long-Term Debt (Less Unamortized Debt Expense) | $ | 61,312,011 | $ | 33,636,051 | $ | 30,316,573 | $ | 30,306,919 | $ | 12,984,169 | ||||||||||
| Stockholders' Equity | 60,040,472 | 55,667,072 | 52,840,991 | 52,020,847 | 49,502,422 | |||||||||||||||
Shares Outstanding at Sept. 30(1) | 7,240,846 | 7,182,434 | 7,112,247 | 7,080,567 | 7,063,989 | |||||||||||||||
Overview
Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 59,80062,000 residential, commercial and industrial customers in Roanoke, Virginia, and the surrounding localities, through its Roanoke Gas Company (“Roanoke Gas”) subsidiary. Roanoke Gas also provides certain unregulated services. Resources formedAs a wholly-owned subsidiary RGC Midstream, LLC ("Midstream"), to invest in the Mountain Valley Pipeline, LLC (the "LLC").of Resources, Midstream is a more than 1% memberinvestor in the LLC.MVP and a less than 1% investor in Southgate. More information regarding the investment in MVP is provided below and under the Equity Investment in Mountain Valley Pipeline section below. The unregulated operations represent less than 2%section.
Primarily due to decisions in January and February 2022 by the Fourth Circuit vacating and remanding certain permits necessary for the completion of revenuesMVP construction and marginsits commercial operation, and the greater uncertainty that exists given the Fourth Circuit's more recent hearing involving an MVP permit, as well as the consequent actions by project partners to impair their respective investments and revocation of Resources.
The utility operations of Roanoke Gas are regulated by the Virginia State Corporation Commission (“SCC”),SCC, which oversees the terms, conditions and rates to be charged to customers for natural gas service, safety standards, extension of service accounting and depreciation. 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. The Federal Energy Regulatory Commission ("FERC") regulates prices for the transportation and delivery of natural gas to the Company’s distribution system and underground storage services. The Company is also subject to other regulations which are not necessarily industry specific.
The Company is also subject to federal regulation from the Department of Transportation in regard to the average numberconstruction, operation, maintenance, safety and integrity of heating degree days (anits 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 measure by which the average daily temperature falls below 65 degrees Fahrenheit) over the most recent 30-year period.
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 CompanyCompany'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 SAVE Rider provides the Company with a purchasedmechanism through which it recovers costs related to SAVE qualified infrastructure investments on a prospective basis, until a formal rate application is filed to incorporate these investments in non-gas base rates. The SAVE Plan and Rider were last 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 continue to increase year over year with fiscal 2022 levels reaching $3,286,000 compared to $2,487,000 in fiscal 2021, reflecting the Company's cumulative investment in qualified SAVE Plan infrastructure since 2019. 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 below.
The WNA mechanism reduces the volatility in earnings due to the variability in temperatures during the heating season. The WNA is based on the most recent 30-year temperature average and provides the Company with a level of earnings protection when weather is warmer than normal and provides its customers with a level of price protection when the weather is colder than normal. The WNA allows the Company to recover from 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 to its customers the excess margin earned for weather that is colder than normal. The WNA mechanism used by the Company is based on a linear regression model that determines the value of a single heating degree day and thereby estimates the revenue adjustment based on weather variance from normal. Any billings or refunds related to the WNA are completed following each WNA year, which extends for the 12-month period from April to March. The Company recorded approximately $1,973,000 and $1,196,000 in additional revenue from the WNA for weather that was approximately 13% and 8% warmer than normal for the fiscal years ended September 30, 2022 and 2021, respectively. 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 trended downward 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, ("PGA"), weather normalization adjustment factor ("WNA"),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 carryingduring the period. Total ICC revenues increased from $396,000 in fiscal 2021 to $657,000 in fiscal 2022 in response to the impact of rising natural gas commodity prices on average natural gas storage balances. Monthly average inventory balances, used to calculate ICC revenues, increased by 69% and ending storage balances increased by 115% year over year.
The cost revenue ("ICC")of natural gas is a pass-through cost and a Steps to Advance Virginia Energy ("SAVE") adjustment rider.
Roanoke Gas is required to submit an AIF each year to the variability in temperatures during the heating season. The WNASCC. Included as part of this filing is based on the most recent 30-year temperature average and providesan earnings test, which is required when the Company with a level of earnings protection when weather is warmer than normal and provides its customers with price protection whenhas certain regulatory assets. If 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. The WNA year runs from April through March. Any billings or refunds related to the WNA are completed following the endresults of the WNA year. Forearnings test indicate that the fiscal year ended September 30, 2017,Company's regulatory earnings exceed the Company recorded $1,839,000 in additional revenue from the WNA for weather that was approximately 18% warmer than normal. During the fiscal year ended September 30, 2016, the Company recorded $1,318,000 in additional revenue for the WNA for weather that was approximately 13% warmer than normal. During the fiscal year ended September 30, 2015, the Company reduced revenue by $609,000 due to the WNA for weather that was approximately 6.5% colder than normal. As normal weather is based on the most recent 30-year temperature average, the heating degree days used to determine normal will change each year as a new year is added to the 30-year period and the oldest year is removed. As a resultmid-point of two consecutive years of significantly warmer winters, the number of heating degree days that defines normal has declined from 4,000 in fiscal 2013 to 3,959 in fiscal 2017. The Company's rates are designed on 4,000 heating degree days from its last non-gas rate filing; however, the WNA model is recovering on the current normal of 3,959 heating degree days, or about 1% less than for what the rates were designed to recover. The 30-year normal will not be reset in base rates until the next time the Company files for a non-gas rate increase, so until such time as normal is reset, the WNA may slightly under-recover for warmer weather.
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 and 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.
Inflation and Rising Prices
Natural gas commodity, delivery and storage capacity costs constitute the single largest expense of the Company representing 61% of fiscal 2022 total operating expenses. Natural gas commodity prices have increased through fiscal 2022 with a sharp rise during the fiscal third and fourth quarters. 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 global energy conditions, including the Russia/Ukraine conflict. 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 higher bad debts related to customers inability to pay higher natural gas bills.
Inflation, due to supply chain delays, labor shortages and limited availability of critical supplies among other factors, affects the Company through increases in non-gas expenses such as labor, employee benefits, materials and supplies, contracted services, corporate insurance and other areas. 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 regularly evaluates the Company's operations, economic conditions and other factors to assess the need to apply for a non-gas rate increase.adjustment. Accordingly, management plans to file a non-gas rate application in early December 2022 to incorporate the increased expense levels and additional rate base, including both SAVE and Non SAVE related plant, since the last non-gas base rate application. See the Regulatory section for more information.
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 information regarding the SAVE Ridersegment analysis is provided in areas where Midstream's investment in affiliates represents a significant component of the comparison. Net income decreased by $41,834,664 to a net loss of $31,732,602 for the year ended September 30, 2022 primarily due to the impairment of the LLC investment and lower equity in earnings.
The Company's operating revenues are affected by the cost of natural gas, as reflected in the consolidated income statement under the Regulatory Affairs section.
Fiscal Year 20172022 Compared with Fiscal Year 2016
The table below reflects operating revenues, volume activity and heating degree-days.
| Operating Revenues | ||||||||||||||
| Year Ended September 30, | 2017 | 2016 | Increase | Percentage | ||||||||||
| Gas Utilities | $ | 61,252,015 | $ | 58,079,990 | $ | 3,172,025 | 5 | % | ||||||
| Other | 1,044,855 | 983,301 | 61,554 | 6 | % | |||||||||
| Total Operating Revenues | $ | 62,296,870 | $ | 59,063,291 | $ | 3,233,579 | 5 | % | ||||||
| Delivered Volumes | |||||||||||
| Year Ended September 30, | 2017 | 2016 | Decrease | Percentage | |||||||
| Regulated Natural Gas (DTH) | |||||||||||
| Residential and Commercial | 5,840,883 | 6,088,108 | (247,225 | ) | (4 | )% | |||||
| Transportation and Interruptible | 2,721,699 | 2,754,497 | (32,798 | ) | (1 | )% | |||||
| Total Delivered Volumes | 8,562,582 | 8,842,605 | (280,023 | ) | (3 | )% | |||||
| Heating Degree Days (Unofficial) | 3,250 | 3,484 | (234 | ) | (7 | )% | |||||
Operating Revenues | ||||||||||||||||
Year Ended September 30, | 2022 | 2021 | Increase / (Decrease) | Percentage | ||||||||||||
Gas Utility | $ | 84,035,644 | $ | 75,045,103 | $ | 8,990,541 | 12 | % | ||||||||
Non Utility | 129,578 | 129,676 | (98 | ) | (0 | )% | ||||||||||
Total Operating Revenues | $ | 84,165,222 | $ | 75,174,779 | $ | 8,990,443 | 12 | % | ||||||||
Delivered Volumes | ||||||||||||||||
Year Ended September 30, | 2022 | 2021 | Increase / (Decrease) | Percentage | ||||||||||||
Regulated Natural Gas (DTH) | ||||||||||||||||
Residential and Commercial | 6,577,369 | 6,773,819 | (196,450 | ) | (3 | )% | ||||||||||
Transportation and Interruptible | 3,747,967 | 3,135,710 | 612,257 | 20 | % | |||||||||||
Total Delivered Volumes | 10,325,336 | 9,909,529 | 415,807 | 4 | % | |||||||||||
HDD | 3,398 | 3,610 | (212 | ) | (6 | )% | ||||||||||
Total gas utility operating revenues for the year ended September 30, 20172022 increased by 5%12% from the year ended September 30, 20162021 primarily due to higher natural gas costscommodity prices, increases in SAVE and increased SAVE PlanICC revenues more than offsettingand higher transportation and interruptible volumes. Rising natural gas commodity prices resulted in a reduction40% per DTH increase in the commodity component of revenue and a 16% per DTH increase in total revenue. The total demand component of revenue remained relatively unchanged as the corresponding transportation and storage fees declined slightly from the prior year. Corresponding to the increase in natural gas deliveries. Thecommodity prices, ICC revenues rose 66% as the average commoditystorage injection price of natural gasper DTH increased by 11% per decatherm sold duefrom $3.19 last year to higher commodity prices. Delivered volumes declined primarily due to weather, as reflected in$7.98 for the lower residential and commercial volumes. Industrial consumption was nearly unchanged. Residential and commercial deliveries tend to be more weather sensitive as reflected by a 4% decline in volumes on 7% fewer heating degree days.current year. Transportation and interruptible volumes, which are primarily driven by production activitiesbusiness activity rather than weather, increased by 20% due to a single multi-fuel customer that switched its primary fuel to natural gas from an alternate energy source. Over the last few years, this customer has alternated its primary energy source between natural gas and alternative fuels. Accordingly, Roanoke Gas expects volatility in the this customer's usage patterns to continue. Excluding the multi-fuel customer's usage from both periods, total transportation and interruptible volumes would have increased by approximately 2% on a comparative basis. The weather sensitive residential and commercial natural gas deliveries decreased by 1%. Other revenues experienced a 6% increase.
| Gross Margin | ||||||||||||||
| Year Ended September 30, | 2017 | 2016 | Increase / (Decrease) | Percentage | ||||||||||
| Gas Utility | $ | 32,332,390 | $ | 31,070,660 | $ | 1,261,730 | 4 | % | ||||||
| Other | 476,767 | 494,254 | (17,487 | ) | (4 | )% | ||||||||
| Total Gross Margin | $ | 32,809,157 | $ | 31,564,914 | $ | 1,244,243 | 4 | % | ||||||
Gross Utility Margin | ||||||||||||||||
Year Ended September 30, | 2022 | 2021 | Increase | Percentage | ||||||||||||
Gas Utility Revenues | $ | 84,035,644 | $ | 75,045,103 | $ | 8,990,541 | 12 | % | ||||||||
Cost of Gas - Utility | 42,496,055 | 35,179,842 | 7,316,213 | 21 | % | |||||||||||
Gross Utility Margin | $ | 41,539,589 | $ | 39,865,261 | $ | 1,674,328 | 4 | % | ||||||||
Gross utility operationsmargin increased by 4% fromover the prior fiscal 2016, primarilyyear primarily as a result of increasingthe aforementioned higher SAVE Plan revenues. Total SAVE Planand ICC revenues, increased by $1,275,000 as the Company continues to investincrease in qualified infrastructure projects. Since January 2014, the Company has invested more than $32,000,000 in qualified SAVE projects with fiscal 2018 projected to add an additional $8,000,000 in SAVE investment. Volumetric
The changes in the components of the gasgross utility margin are summarized below:
| Twelve Months Ended September 30, | |||||||||||
| 2017 | 2016 | Increase / (Decrease) | |||||||||
| Customer Base Charge | $ | 12,412,753 | $ | 12,364,811 | $ | 47,942 | |||||
| SAVE Plan | 3,813,043 | 2,538,055 | 1,274,988 | ||||||||
| Volumetric | 13,573,704 | 14,099,214 | (525,510 | ) | |||||||
| WNA | 1,839,454 | 1,317,800 | 521,654 | ||||||||
| Carrying Cost | 588,624 | 651,492 | (62,868 | ) | |||||||
| Other | 104,812 | 99,288 | 5,524 | ||||||||
| Total | $ | 32,332,390 | $ | 31,070,660 | $ | 1,261,730 | |||||
| Years Ended September 30, | Increase | ||||||||||
2022 | 2021 | (Decrease) | ||||||||||
Customer Base Charge | $ | 14,557,492 | $ | 14,563,274 | $ | (5,782 | ) | |||||
SAVE Plan | 3,285,518 | 2,487,299 | 798,219 | |||||||||
Volumetric | 20,901,637 | 21,188,794 | (287,157 | ) | ||||||||
WNA | 1,972,801 | 1,196,499 | 776,302 | |||||||||
ICC | 657,042 | 395,626 | 261,416 | |||||||||
Other Revenues | 165,099 | 33,769 | 131,330 | |||||||||
Total | $ | 41,539,589 | $ | 39,865,261 | $ | 1,674,328 | ||||||
Operations and Maintenance Expense
- Operations and maintenanceGeneral Taxes - General taxes decreased by $4,893, or less than 1%. Property tax expense was nearly unchanged as a 7% increase in a reduction of 18 employees. The personnel savings from this work force reductiongross utility property was offset by the fees paid to the service provider. Employee benefit costs increased by $195,000 due to higher health insurance premiums and higher actuarial determined costs on the post-retirement medical plan. The Company realized a $251,000 reduction in corporate property and liability insurance premiums due to favorable insurance renewals. Capitalized overheads, which include general and administrative, payroll and engineering costs, decreased by $179,000 from fiscal 2016 primarily due to acorresponding reduction in the general and administrative overhead rate and less LNG overheads dueassessed values reported by the SCC to a 46% reduction in the amount of LNG produced. The reduction in the LNG production was timing related as the facility was at near full capacity at September 30, 2016, while the balance at September 30, 2017 was at 79% capacity. Legal and other professional expenses were also lower due to reduced activity in those areas.
Depreciation
- Depreciation expense increased byEquity in Earnings of Unconsolidated Affiliate
- The equity in earnings of theImpairment of Unconsolidated Affiliates - The $55,092,303 impairment is due to two other-than-temporary write-downs of the Company's investment in the LLC that were made during the second and fourth quarters of fiscal 2022. See Equity Investment in Mountain Valley Pipeline and Critical Accounting Policies and Estimates sections for more information.
Other ExpenseIncome, net - Other expense, net, decreasedincome increased by $123,139,$544,837, or 48%60%, primarily due to lower pipeline assessmentsa $345,000 decrease in the non-service cost components of net periodic benefit costs and charitable commitments.
Interest Expense
- Total interest expense increased byRoanoke Gas' interest expense increased by $189,819, or 7%, as total average debt outstanding increased by $7,300,000 associated with two new debt issues totaling $25,000,000, of which the proceeds were used to pay down the capital bridge financing provided by the line-of-credit and contribute additional financing for the capital budget. The average interest rate decreased slightly from 3.48% in fiscal 2021 to 3.38% in fiscal 2022. The lower average interest rate was attributable to the two new debt issues that have interest rate swap rates of 2.00% and 2.49%, respectively.
Midstream's interest expense increased by $256,225, or 21%, as the average interest rate on Midstream's total debt increased from 2.23% to 2.59% related to rising interest rates on the variable rate credit facility combined with a $2,600,000 increase in total average debt outstanding during the current year from 3.76% to 3.56%. The $7,000,000 unsecured note issued on November 1, 2016 had a variable rate that ranged from 1.43% to 2.14% during the year, which was lower than the average rate on the outstanding debt during fiscal 2016.
Income Taxes
- Income tax expenseEarnings Per Share and Dividends - Basic and diluted loss per share were $3.48 in fiscal 2022 compared to $1.22 earnings per share were $0.86 in fiscal 2017 compared to $0.81 in fiscal 2016.2021. Dividends declared per share of common stock were $0.58$0.78 in fiscal 20172022 compared to $0.54$0.74 in fiscal 2016. All per share amounts were restated for the three-for-two stock split effective March 1, 2017 as described in Note 2 to the Consolidated Financial Statements.
| Operating Revenues | ||||||||||||||
| Year Ended September 30, | 2016 | 2015 | Decrease | Percentage | ||||||||||
| Gas Utilities | $ | 58,079,990 | $ | 67,094,290 | $ | (9,014,300 | ) | (13 | )% | |||||
| Other | 983,301 | 1,095,317 | (112,016 | ) | (10 | )% | ||||||||
| Total Operating Revenues | $ | 59,063,291 | $ | 68,189,607 | $ | (9,126,316 | ) | (13 | )% | |||||
| Delivered Volumes | |||||||||||
| Year Ended September 30, | 2016 | 2015 | Decrease | Percentage | |||||||
| Regulated Natural Gas (DTH) | |||||||||||
| Residential and Commercial | 6,088,108 | 6,955,594 | (867,486 | ) | (12 | )% | |||||
| Transportation and Interruptible | 2,754,497 | 2,919,413 | (164,916 | ) | (6 | )% | |||||
| Total Delivered Volumes | 8,842,605 | 9,875,007 | (1,032,402 | ) | (10 | )% | |||||
| Heating Degree Days (Unofficial) | 3,484 | 4,253 | (769 | ) | (18 | )% | |||||
| Gross Margin | ||||||||||||||
| Year Ended September 30, | 2016 | 2015 | Increase / (Decrease) | Percentage | ||||||||||
| Gas Utility | $ | 31,070,660 | $ | 29,656,975 | $ | 1,413,685 | 5 | % | ||||||
| Other | 494,254 | 549,458 | (55,204 | ) | (10 | )% | ||||||||
| Total Gross Margin | $ | 31,564,914 | $ | 30,206,433 | $ | 1,358,481 | 4 | % | ||||||
| Twelve Months Ended September 30, | |||||||||||
| 2016 | 2015 | Increase / (Decrease) | |||||||||
| Customer Base Charge | $ | 12,364,811 | $ | 12,240,580 | $ | 124,231 | |||||
| SAVE Plan | 2,538,055 | 1,307,795 | 1,230,260 | ||||||||
| Volumetric | 14,099,214 | 15,757,907 | (1,658,693 | ) | |||||||
| WNA | 1,317,800 | (608,560 | ) | 1,926,360 | |||||||
| Carrying Cost | 651,492 | 833,291 | (181,799 | ) | |||||||
| Other | 99,288 | 125,962 | (26,674 | ) | |||||||
| Total | $ | 31,070,660 | $ | 29,656,975 | $ | 1,413,685 | |||||
Capital Resources and Liquidity
Due to the capital intensive nature of the utility business, as well as the relatedimpact of weather sensitivity,variability, the Company’s primary capital needs are for the funding of its continuing construction program,capital projects, investment in the LLC, the seasonal funding of its natural gas inventories and accounts receivables and payment of dividends. To meetdividends to shareholders. The Company anticipates funding these needs, the Company relies onitems through its operating cash flows, line-of-credit agreement,credit availability under short-term and long-term debt agreements and capital raised throughproceeds from the Company’s stock plans.
Cash and cash equivalents decreasedincreased by $573,612approximately $3.4 million in fiscal 2017 and $341,9822022 compared to $1.2 million in fiscal 2016 compared to an increase of $135,477 in fiscal 2015.2021. The following table summarizes the categories of sources and uses of cash:
Cash Flow Summary | Years Ended September 30, | |||||||
2022 | 2021 | |||||||
Net cash provided by operating activities | $ | 15,551,676 | $ | 11,568,108 | ||||
Net cash used in investing activities | (30,615,878 | ) | (25,849,237 | ) | ||||
Net cash provided by financing activities | 18,444,799 | 15,508,380 | ||||||
Net increase in cash and cash equivalents | $ | 3,380,597 | $ | 1,227,251 | ||||
| Cash Flow Summary | Year Ended September 30, | ||||||||||
| 2017 | 2016 | 2,015 | |||||||||
| Net cash provided by operating activities | $ | 12,980,978 | $ | 14,921,640 | $ | 16,760,827 | |||||
| Net cash used in investing activities | (23,492,555 | ) | (20,996,501 | ) | (13,750,274 | ) | |||||
| Net cash provided by (used in) financing activities | 9,937,965 | 5,732,879 | (2,875,076 | ) | |||||||
| Increase (decrease) in cash and cash equivalents | $ | (573,612 | ) | $ | (341,982 | ) | $ | 135,477 | |||
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 provided byflows from operating activities was $12,981,000increased by nearly $4 million from the prior year. The table below summarizes the significant components operating cash flow:
| Years Ended September 30, | Increase | ||||||||||
Cash Flows From Operating Activities: | 2022 | 2021 | (Decrease) | |||||||||
Net Income (Loss) | $ | (31,732,602 | ) | $ | 10,102,062 | $ | (41,834,664 | ) | ||||
Non-cash adjustments: | ||||||||||||
Depreciation | 9,182,751 | 8,669,977 | 512,774 | |||||||||
Equity in earnings | (73,327 | ) | (1,667,554 | ) | 1,594,227 | |||||||
AFUDC | (75,154 | ) | (55,981 | ) | (19,173 | ) | ||||||
Allowance for doubtful accounts | 129,260 | (461,130 | ) | 590,390 | ||||||||
Impairment of unconsolidated affiliates | 55,092,303 | — | 55,092,303 | |||||||||
Changes in working capital and regulatory assets and liabilities: | ||||||||||||
Accounts receivable | (532,630 | ) | (1,084,726 | ) | 552,096 | |||||||
Gas in Storage | (9,049,181 | ) | (2,158,709 | ) | (6,890,472 | ) | ||||||
Prepaid income taxes | 17,195 | (2,457,327 | ) | 2,474,522 | ||||||||
Accounts payable and accrued expenses | 310,700 | 2,862,861 | (2,552,161 | ) | ||||||||
Deferred Taxes | (14,258,294 | ) | 106,188 | (14,364,482 | ) | |||||||
Change in over (under) collection of gas costs | 3,731,584 | (3,314,446 | ) | 7,046,030 | ||||||||
WNA | (185,414 | ) | (609,888 | ) | 424,474 | |||||||
Supplier refunds | 2,484,992 | — | 2,484,992 | |||||||||
Non-current regulatory liabilities | 507,116 | 2,367,512 | (1,860,396 | ) | ||||||||
Other | 2,377 | (730,731 | ) | 733,108 | ||||||||
Net cash provided by operating activities | $ | 15,551,676 | $ | 11,568,108 | $ | 3,983,568 | ||||||
Recovery of the prior year under-collection of gas costs and receipt of supplier refunds, net of the impact of the continuing rise in fiscal 2017, $14,922,000 in fiscal 2016 and $16,761,000 in fiscal 2015. Cash provided by operating activities decreased by more than $1,900,000 from last year primarily as a result of natural gas commodity prices, ending their steady price decline and a smalleraccounted for much of the nearly $4 million increase in deferred tax liabilities associated withoperating cash flows. At September 30, 2021, Roanoke Gas was in a net under-collected gas cost position of more than $5 million due to timing in adjusting the continuation of bonus depreciation. Commodity prices had been declining since 2014, resulting in lower naturalPGA factor for rising gas storage costs. During fiscal 2017,2022, Roanoke Gas collected, through customer billings, nearly $3.6 million of the prior year under-collection. Roanoke Gas also received supplier refunds totaling nearly $2.7 million from the pipelines that serve the Company. These refunds are required to be returned to customers over a 12 month period, which began in July 2022. As noted above, natural gas prices reversed this trendhave risen steadily over the last two years; however, commodity prices took a sharp increase during the summer of fiscal 2022, which resulted in an increase in gas in storage of more than $9 million over the same period last year. The prior fiscal year also reflected an increase of $2.1 million as natural gas prices increased at a slower pace. As a result, the change in under-collection of gas costs and increased, resultingthe receipt of the supplier refunds provided $7.0 million and $2.5 million in additional operating cash flow over last year, while the much higher cost of gas in storage.storage resulted in a reduction of $6.9 million in operating cash flow from last year. The Company continues to benefit fromimpairments on the application of bonus depreciation for federal
Other significant fluctuations in the near future resulting in cash outflows as these taxes are paid. A summary of the key components of the cash flows from operating activities is provided below:
| Twelve Months Ended September 30, | |||||||||||
| Cash Flows From Operating Activities: | 2017 | 2016 | Increase (Decrease) | ||||||||
| Net income | $ | 6,232,865 | $ | 5,806,866 | $ | 425,999 | |||||
| Depreciation | 6,378,368 | 5,709,525 | 668,843 | ||||||||
| Decrease in gas in storage | (265,109 | ) | 723,713 | (988,822 | ) | ||||||
| Increase in deferred taxes | 3,325,379 | 4,466,954 | (1,141,575 | ) | |||||||
| Accounts payable and accrued expenses | (989,683 | ) | 15,046 | (1,004,729 | ) | ||||||
| Other | (1,700,842 | ) | (1,800,464 | ) | 99,622 | ||||||
| Net cash provided by operating activities | $ | 12,980,978 | $ | 14,921,640 | $ | (1,940,662 | ) | ||||
Cash Flows Used in Investing Activities:
Investing activities primarily consist of expenditures under the Company’s construction program,related to investment in Roanoke Gas' utility property, which involves a combination ofincludes replacing aging natural gas pipe with new plastic or coated steel pipe, making improvements to the LNG plant and gas distribution system facilities expandingand expansion of its natural gas system to meet the demands of customer growth, as well as theMidstream's continued investment in the MVP. The Company’sLLC. Roanoke Gas' expenditures related to its pipeline renewal programwere approximately $25.5 million and other system and infrastructure improvements increased to more than $20,700,000$20.0 million in fiscal 2017 from $18,000,000 in fiscal 20162022 and $13,800,000 in fiscal 2015. The Company renewed 9 miles of natural gas distribution main and replaced 459 services in fiscal 2017. This compares to 14.92021, respectively. Roanoke Gas renewed 8.3 miles of main and 684 services605 service lines and 7.8 miles of main and 620 service lines in fiscal 2016years 2022 and 10 miles of main and 594 services in fiscal 2015.2021, respectively. The Company completedcurrent SAVE Plan is focused on the replacement of its cast iron and bare steelpre-1973 first generation plastic pipe in late 2016. In addition the Company’sto other SAVE related infrastructure. Furthermore, Roanoke Gas’ capital expenditures included costs to extend natural gas distribution mains and services to 499 new 544 customers in fiscal 2022, compared to 480 customers in fiscal 2017 compared to 495 new customers in fiscal 2016 and 609 in fiscal 2015. Although the level of expenditures under the pipeline renewal program declined in fiscal 2017 as the Company transitioned from cast iron and bare steel to first generation plastic pipe replacement, the Company exceeded last year's capital spending with the completion of the automated meter reading ("AMR") project. The AMR project involved the retrofitting of all customer meters with transmitters to allow consumption data to be collected remotely. The AMR system provides the Company with an efficient data collection process for more reliable and accurate measure of natural gas usage by its customers.2021. Depreciation covered approximately 31% of36% and 43% of the current and prior year's capital expenditures, compared to 32% for 2016 and 38% for 2015,respectively, with the balance provided from other operating cash flows and borrowings.
Capital expenditures are expected to remain at elevated levelsbe around $20 million annually over the next few years. The Company is now focusedyears as Roanoke Gas continues to focus on replacing the remaining pre-1973 first generation plastic pipe with polyethylene pipe. This renewal project is expected to be completed by 2021. The current capital budget for fiscal 2018 is projected at more than $20,000,000, consistent with fiscal 2017 levels. In addition to the replacement of pre-1973 plastic pipe, the Company plans to invest approximately $3,000,000 for customer growth, replace a natural gas transfer station and reinforce sectionsits SAVE Plan, completion of the distributionRNG project, as well as system to meet increasing demandimprovements and ensure reliability of gas service.customer growth. The Company expects to increaseutilize its borrowing activitycredit facilities, as well as consider additional equity capital, to meet the funding requirements of these planned expenditures.
Investing cash flows also reflect the Company's $2,759,346fiscal 2022 funding of its$5.3 million for Midstream's participation in the LLC. The Company expectsBased on the LLC's managing partner's most recent projections, Midstream's total expected funding requirement is expected to invest a total of $35increase to between $68 and $70 million inas discussed below, with anticipated cash investment to be approximately $13 million over the project.next 12 to 24 months. Funding for the investment in the LLC is provided through a combination of a $25 millionMidstream's credit facility which maturesand three unsecured notes in 2020, and equity capital. The Company may consider issuing additional common stock in 2018 to supplement the debt financing. When the $25 million credit facility matures, the Company will consider its financing options, which may included longer-term debt financing.combined amount of $32 million. More
Cash Flows Provided by (Used in) Financing Activities:
Financing activities generally consist of borrowings and repayments under debtcredit agreements, issuance of stock and the payment of dividends. As mentioned above, the Company uses its line-of-credit to fund seasonal working capital and provide temporary financing for capital projects, which is then converted into longer-term debt or equity financing. CashNet cash flows provided by financing activities were $9,938,000$18.4 million and $15.5 million in fiscal 20172022 and $5,733,000 in fiscal 2016 compared to cash used2021, respectively. The increase in financing activitiescash flows was primarily attributable to Resources' $27 million equity offering in March 2022 of $2,875,000which $12 million was invested in fiscal 2015. The combinationRoanoke Gas and $10 million in Midstream. Due to these cash infusions from the equity issue and the issuance of greater capital investmentRoanoke Gas' $15 million and $10 million unsecured notes and Midstreams' $8 million note, Roanoke Gas was able to pay down its line-of-credit balance and maturing $7 million note and Midstream applied $18 million against its non-revolving credit facility and $125,000 related to the pipeline renewal program and other projects, including the Mountain Valley Pipeline, and lower cash flows from operating activities increased net borrowing. As noted above, the Company's operating cash flows have declined since 2015 as the benefits from declining natural gas prices and bonus depreciation have lessened. The Company increased the net utilization of its line-of-credit by $3,235,000 to provide bridge financing for its capital budget.an amortizing note. The Company also entered into a 5-year unsecured note in the principal amount of $7,000,000 on November 1, 2016. The proceeds from this note were used to convert a portion of the line-of-credit balance supporting Roanoke Gas' capital expenditures into a longer-term financing instrument. The remaining $2,916,000 increase in unsecured notes payable is attributable to the borrowing under Midstream's credit facility to finance the investment in MVP. Proceedsrealized another $2.0 million from the issuance of stock were $968,000 underthrough DRIP activity, the Company's stock plans. Dividends increasedATM program and the exercise of options. Cash out-flows for dividend payments exceeded $7.0 million as the annualized dividend rate increased from $0.74 to $0.78 per share went from $0.51 in fiscal 2015 to $0.54 in fiscal 2016 and $0.58 in fiscal 2017.
Based on the LLC's projected cash requirements for MVP, which includes MVP construction resuming in 2023, Midstream will need between $15 million and $17 million in additional capital over last year duethe next 12 to 24 months to meet its funding commitments to the extensionLLC and cover Midstream's operating and financing expenses. Additionally, the $21.9 million credit facility is scheduled to mature on December 31, 2023 as well as debt service related to monthly and quarterly scheduled installment payments on two of the line-of-credit term to more than one year resultingMidstream's unsecured notes in fiscal 2023 and 2024. Various options are being evaluated, including seeking additional borrowing capacity from its transition to a non-current debt as noted below.
As of September 30, 2022, Roanoke Gas entered into a new revolvinghad $28 million available under its line-of-credit note agreement. In addition, Roanoke Gas also has private shelf agreements with two different financial institutions. The new line-of-creditfirst agreement provides for the issuance of up to $40 million in unsecured notes in addition to the $28 million previously issued. This shelf agreement is for a two-year term expiring March 31, 2019, replacing the one-yearscheduled to expire on December 6, 2022; however, management expects to reach an agreement that expired on March 31, 2017. As the new agreement is for a two-year term, amounts drawn against the new agreement are considered to be non-current as the balance outstanding under the line-of-credit will not be subject to repayment within the next 12-month period. Therefore, the balance sheet at September 30, 2017 reflects the line-of-credit balance as part of long-term debt while the prior year's balance is classified as a current liability. The new agreement maintains the same variable interest rate based on 30-day LIBOR plus 100 basis points and availability fee of 15 basis points applied to the unused balance. The new agreement also maintains the multi-tiered borrowing limits to accommodate seasonal borrowing demands and minimize borrowing costs. The total available borrowing limits duringextend the term of the newagreement. The second agreement range from $10,000,000provides for the issuance of up to $30,000,000. The Company intends to request an extension of the agreement by one year prior to next March when the outstanding$70 million in unsecured notes during its current term, which expires September 30, 2025. These debt would become a current liability; however, there is no guarantee that the line-of-credit agreement will be extended or replaced on terms comparable to those currently in place.
Notes 6 and 7 provide details on the Company's line-of-credit and three debt issuances mentioned above.
ATM Program
Resources issued two 10-year unsecured notes4,872 shares of common stock for $112,500, net of $2,813 in fees, under the aggregate principal amount of $8,000,000 with a fixed interest rate of 3.58% per annum. Interest is paid semi-annually on these notes in April and October of eachATM program for the year until the notes mature. The proceeds from these notes were used to refinance a portion of the line-of-credit balance outstanding atended September 30, 2017 into longer-term financing.
Off-Balance Sheet Arrangements
The Company has no off-balance sheet arrangements as defined in Regulation S-K, Item 303(a)(4)(ii).
| Recorded contractual obligations: | Less than 1 year | 1-3 Years | 4-5 Years | After 5 Years | Total | ||||||||||||||
| Long-Term Debt - Notes Payable (1) | $ | — | $ | — | $ | 13,312,200 | $ | 30,500,000 | $ | 43,812,200 | |||||||||
| Long-Term Debt - Line of Credit (2) | — | 17,791,760 | — | — | 17,791,760 | ||||||||||||||
| Total | $ | — | $ | 17,791,760 | $ | 13,312,200 | $ | 30,500,000 | $ | 61,603,960 | |||||||||
| (1) See Note 6 to the consolidated financial statements. Does not include scheduled debt payments for the unsecured notes issued on October 2, 2017. | |||||||||||||||||||
| (2) See Note 5 to the consolidated financial statements. New line-of-credit agreement executed for a 2-year term, expiring March 31, 2019. Amounts drawn against agreement are considered non-current as they are not subject to repayment within 12-months. | |||||||||||||||||||
| Unrecorded contractual obligations, not reflected in consolidated balance sheets in accordance with US GAAP: | Less than 1 year | 1-3 Years | 4-5 Years | After 5 Years | Total | ||||||||||||||
| Pipeline and Storage Capacity (3) | $ | 11,232,436 | $ | 17,746,270 | $ | 9,787,494 | $ | 3,067,053 | $ | 41,833,253 | |||||||||
| Gas Supply (4) | — | — | — | — | — | ||||||||||||||
| Interest on Line-of-Credit (5) | 58,338 | 25,800 | — | — | 84,138 | ||||||||||||||
| Interest on Notes Payable (6) | 1,641,613 | 3,283,226 | 2,819,856 | 15,541,764 | 23,286,459 | ||||||||||||||
| Pension Plan Funding (7) | — | — | — | — | — | ||||||||||||||
| Investment in MVP (8) | 25,560,133 | 4,741,780 | — | — | 30,301,913 | ||||||||||||||
| Other Obligations (9) | 146,787 | 10,087 | 4,661 | 25,540 | 187,075 | ||||||||||||||
| Total | $ | 38,639,307 | $ | 25,807,163 | $ | 12,612,011 | $ | 18,634,357 | $ | 95,692,838 | |||||||||
| (3) Recoverable through the PGA process. | |||||||||||||||||||
| (4) Volumetric obligation is for the purchase of contracted decatherms of natural gas at market prices in effect at the time of purchase. Unable to estimate related payment obligation until time of purchase. See Note 11 to the consolidated financial statements. | |||||||||||||||||||
| (5) Accrued interest on line-of-credit balance at September 30, 2017, including minimum facility fee on unused line-of-credit. See Note 5 to the consolidated financial statements. | |||||||||||||||||||
| (6) Calculated interest payments on 20-year $30.5 million Roanoke Gas Co. Prudential note payable due September 18, 2034, 5-year $7 million Roanoke Gas Co. BB&T note payable due November 01, 2021 and on the 09/30/2017 balance on Midstream notes due December 29, 2020. See Note 6 to the consolidated financial statements. Does not include scheduled interest payments on the unsecured notes issued on October 2, 2017. | |||||||||||||||||||
| (7) Estimated minimum funding assuming application of credit balances in plan to offset funding. Minimum funding requirements beyond five years is not available. See Note 8 to the consolidated financial statements for the planned funding in fiscal 2018. | |||||||||||||||||||
| (8) Projected remaining funding of the Company's 1% interest in MVP as entered into on October 1, 2015. | |||||||||||||||||||
| (9) Various lease, maintenance, equipment and service contracts. | |||||||||||||||||||
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, the MVP project has been subject to repeated, significant delays and cost increases because of legal and regulatory setbacks, particularly in respect of litigation in the Fourth Circuit in January and February 2022 as discussed below.
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. On April 8, 2022, the FERC authorized the amended CPCN.
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). The State 401 Approvals were both issued in December 2021 and are the subject of ongoing litigation.
On January 25, 2022, the LLC’s authorizations related to the Jefferson National Forest (JNF) received from the Bureau of Land Management and the U.S. Forest Service were vacated and remanded on specific issues by the Fourth Circuit. On February 3, 2022, the Fourth Circuit vacated and remanded on specific issues the Biological Opinion and Incidental Take Statement issued by the United States Department of the Interior’s Fish and Wildlife Service for MVP. On May 3, 2022, the operator for MVP announced that after evaluating legal options and consulting with the relevant federal agencies, the LLC planned to pursue new authorizations relating to the JNF and a new Biological Opinion and Incidental Take Statement. Related to pursuing a new Biological Opinion and Incidental Take Statement, on July 29, 2022, the LLC submitted to the U.S. Fish and Wildlife Service an updated supplement to the Biological Assessment (and notified the FERC of such submission), which updated supplement is intended to address aspects of the Fourth Circuit's February 2022 ruling and points raised by project opponents.
Given ongoing litigation and regulatory matters, on June 24, 2022, the LLC filed a request with the FERC for an extension of time to complete the project for an additional four years (relative to a prior obtained extension) through October 13, 2026, which request was granted on August 23, 2022.
On October 1, 2015,25, 2022, oral argument was held in the Fourth Circuit relating to the WVDEP State 401 approval, which oral argument was conducted by the same panel of Fourth Circuit judges as have appeared, and overruled permitting agencies, in numerous prior matters relating to the MVP. Based upon the oral argument, the project operator perceives continued hostility to and risk posed by the Fourth Circuit panel to the LLC’s State 401 Approvals and those potential future authorizations and permits within the Fourth Circuit’s jurisdiction, including any new authorizations for the JNF and new Biological Opinion and Incidental Take Statement. Further, as of the filing of this Annual Report on Form 10-K, there remains uncertainty with respect to the relevant federal agencies' final permitting issuance timelines.
Notwithstanding prior setbacks and ongoing risks, the MVP Joint Venture continues to engage in pursuing the requisite authorizations necessary under applicable law from the relevant agencies to complete the MVP project. However, in light of the continuing and likely future litigation and regulatory challenges posed to the MVP project (including the need for existing or future authorizations to remain in effect notwithstanding any pending or future challenge thereto) and timing uncertainties within the permitting process, the Company through its wholly-owned subsidiary Midstream, entered into an agreementbelieves that the best path to becomecomplete the MVP in accordance with the Company’s previously-communicated targeted full in-service date for the project during the second half of 2023 and at a 1% membertargeted total project cost of approximately $6.6 billion (excluding AFUDC) is for the United States Congress to expeditiously pass, and there to be enacted, federal energy infrastructure permitting reform legislation that specifically requires the completion of the MVP project, similar to MVP-specific aspects of legislation proposed in September 2022 by each of United States Senators Joseph Manchin and Shelley Moore Capito.
As noted above, the LLC has sought new authorizations relating to the JNF, a new Biological Opinion and Incidental Take Statement, and the Army Corps Individual Permit. In order to complete the project, in addition to the authorizations with respect to water crossings and other relevant regulatory matters, the LLC needs to continue to have available the orders previously issued by the FERC that are necessary to complete the MVP project and 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 in the JNF. The LLC also is participating in the defense of the State 401 Approvals, which are the subject of ongoing litigation in the Fourth Circuit.
Resources' earnings from MVP are primarily attributable to AFUDC income generated by the LLC. The purposeLLC 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. In November 2021, the LLC suspended the accrual of AFUDC for the winter curtailment period and until such time as growth construction activities may resume. Additionally, Roanoke Gas continues the suspension of AFUDC accruals on its two gate stations that will interconnect with MVP until such time as construction activities resume on the respective gate stations.
In April 2018, the LLC announced the Southgate project and submitted Southgate's certificate application to the FERC in November 2018. In June 2020, the FERC issued the CPCN for 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 MVP and the Director of the Office of Energy Projects lifts the stop work order and authorizes the LLC is to constructcontinue constructing MVP. In addition, there have been certain other litigation and operateregulatory-related delays affecting completion of the Mountain Valley Pipeline ("MVP"),MVP Southgate project, including on August 11, 2020, the North Carolina Department of Environmental Quality denied Southgate's application for a natural gasClean Water Act Section 401 Individual Water Quality Certification and Jordan Lake Riparian Buffer Authorization due to uncertainty surrounding MVP's completion, which denial was reissued in April 2021 following an appellate proceeding. On December 3, 2021, the Virginia State Air Pollution Control Board denied the permit for Southgate's Lambert compressor station, which decision the LLC initially appealed before withdrawing its request to review the denial.
Given the continually evolving regulatory and legal environment for greenfield pipeline connectingconstruction projects, as well as factors specific to MVP and Southgate, the Equitrans gatheringLLC continues to evaluate Southgate including engaging in discussions with Dominion Energy North Carolina regarding options with respect to Southgate, including likely refining the project's design, scope and transmission system in northern West Virginia to the Transco interstate pipeline in south central Virginia. This project fallstiming. Dominion Energy North Carolina's obligations under the jurisdictionprecedent agreement in support of FERC andthe original project are subject to certain conditions, including that the LLC would have completed construction of the project facilities by June 1, 2022, which deadline is subject to its approval prior to beginning construction. On October 13, 2017, FERC issued the MVP Certificateextension by virtue of Public Convenience and Necessity ("CPCN"). Pending Virginia and West Virginia state environmental agency permits and other federal agency permits,previously declared events of force majeure. The project operator has announced that it is expectedunable to predict the results of the discussions between the LLC and Dominion Energy North Carolina, including any potential modifications to the project, or ultimate undertaking or completion of the project.
Management conducted an assessment of its investment in the LLC 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 concluded that FERC will issue a construction Notice-to-Proceed ("NTP") in late 2017 or early 2018. If the NTP is received on this schedule, the MVP targeted in-service date is late fourth quarter of 2018.
Midstream had borrowing capacity of $23 million under its non-revolving credit facility, which matures in December 2023. As of September 30, 2022, $21.9 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 re-financed through a separate unsecured promissory note. Effective March 31, 2022, the borrowing capacity under the credit facility was further reduced to its distribution system. Currently, Roanoke Gas is served by two pipelines and a liquefied natural gas storage facility. Damagecurrent $23 million level as $10 million of the outstanding balance was paid. See Note 7 for more information. This credit facility will provide limited financing capacity for MVP funding; however, due to or interruption in supply from any of these sources, especially during
Regulatory
In April 2020, the SCC issued an order allowing regulated utilities in MVP will continueVirginia to growdefer certain incremental, prudently incurred costs associated with the COVID-19 pandemic and to apply for recovery at a steady pace until such time FERC issues their decisionfuture date. Roanoke Gas deferred certain COVID-19 related costs during fiscal 2022 and 2021. However, based on the project. WhenCompany’s preliminary earnings test for those years, Roanoke Gas' earnings exceeded the NTP is received, constructionauthorized return on equity on which the pipeline should beginCompany’s rates were established in earnestits last rate proceeding. Accordingly, Roanoke Gas expensed $57,000 and both$217,000 in COVID-19 related deferred costs during the investment in MVPfourth quarter of fiscal 2022 and the AFUDC will increase at a much greater rate until the pipeline is placed in service. Earnings after the pipeline is operational would be derived from the fees charged for transporting natural gas through the pipeline.2021, respectively.
Roanoke Gas continues to recover the costs of its infrastructure replacement program through its SAVE Plan. On June 30, 2017, the CompanyRider. In May 2022, Roanoke Gas filed its 2018most recent SAVE Plan application with the SCC. The originalSCC to update the SAVE Plan and Rider were approved byfor the period October 2022 through September 2023. The updated SAVE Rider is designed to collect approximately $4.1 million in annual revenues representing approximately a $650,000 increase over the current SAVE Rider. The Company received a final order from the SCC through an order issuedon the SAVE Rider application on August 29, 201223, 2022 approving the application with the new rates placed into effect in October 2022.
On May 16, 2022, Roanoke Gas announced a cooperative agreement under which Roanoke Gas and has been modified, amendedthe Western Virginia Water Authority will produce commercial quality renewable natural gas, or updated each year since.RNG, from biogas produced at the regional water pollution control plant. In August 2022, Roanoke Gas filed an application with the SCC seeking approval of a rate adjustment clause under which the Company will recover the costs associated with constructing, owning, operating and maintaining the renewable natural gas facility. The original SAVE Planapplication was designed to facilitate the accelerated replacementfiled under Chapter 30 of Title 56 of the remaining bare steel and cast ironCode of Virginia. The Company expects a final order from the Commission in January 2023.
On June 2, 2022, Roanoke Gas filed an application with the SCC to acquire certain natural gas pipe by providingdistribution assets from a mechanismlocal housing authority. Under this application, the Company requested the approval to acquire such facilities at five separate apartment complexes, located in the Company’s service territory, that were under housing authority management. Under the proposed plan, the housing authority would renew existing natural gas distribution facilities to include mains, services and meter installations and then transfer ownership of these facilities to Roanoke Gas. In turn, Roanoke Gas would assume responsibility for the Company to recover the related depreciationoperation and expensesmaintenance of these assets and return on rate base of the additional capital investment without the filing ofrecognize a formal application for an increase in non-gas base rates. The projects included under the SAVE Plan will enhance the safety and reliability of the Company’s gas distribution system and reduce greenhouse emissions. The amendments in 2013 and 2014 added projectsgain related to the replacement of bare steel and cast iron natural gas pipe in additionasset acquisition equal to two other major projects and the investment for related meter and regulator installations located on customer premises. In 2015,cost associated with the renewal.
On July 19, 2022, the SCC approved the Company's requestapplication and on August 4, 2022, the housing authority transferred the assets from two apartment complexes to expandRoanoke Gas. Roanoke Gas recorded these assets and recognized a pre-tax gain of approximately $219,000 during the authorized annual spending variance from 10%Company’s fiscal fourth quarter. The housing authority expects to 20%complete the upgrade and set a 5% cumulative SAVE spending variance. This allowssubsequent asset transfer at one more apartment complex in fiscal 2023. The authority is awaiting future funding to complete two additional apartment complexes. The timing of funding and the completion of the asset renewals for these two complexes is unknown at this time.
On September 30, 2022, the Company filed notice with the SCC that it intended to recover it's investment upfile a non-gas base rate case. The Company plans to file in early December with the new variance limits. rates expected to become effective on January 1, 2023 on an interim basis subject to refund.
The 2016 and 2017 applications included provisions to continuefinal order from the ongoing pipeline renewal project withlast non-gas base rate increase excluded from current rates a focus on pre-1973 plastic pipe, replacement of natural gas custody transfer stations and the replacement of coated steel tubing services and related meter installations. The 2018 SAVE Plan continues the focusreturn on the replacementinvestment in two gate stations that would interconnect with the MVP; however, the SCC allowed Roanoke Gas to defer the related financing costs of the pre-1973 plastic pipe and the replacement of one custody transfer station. On September 28, 2017,those investments for possible future recovery. As a result, the Company received SCC approvalbegan recognizing AFUDC during the second quarter of fiscal 2020 to implementcapitalize both the new 2018 SAVE ratesequity and debt financing costs incurred during the construction phases. Beginning January 2021, Roanoke Gas temporarily ceased recording AFUDC on its related MVP interconnect construction projects until such time as construction activities resume. For the year ended September 30, 2021, the Company recognized a total of $55,981 in AFUDC related to the proposed qualifying SAVE investmentstwo gates stations, $41,978 of equity and $14,003 of debt carrying costs. In connection with the RNG project, Roanoke Gas began accruing AFUDC in calendar 2018. fiscal 2022 associated with construction of the facility. For the year ended September 30, 2022, Roanoke Gas recognized a total of $75,154 in AFUDC, $59,243 of equity and $15,911 of debt carrying costs.
The new rates are designedservice disconnection moratorium under which the Company had 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 were 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 provide approximately $5,000,000 in revenue, representing an increase of $1,000,000 over the estimated 2017 SAVE Plan year. The additional SAVE Plan revenue as approvedassist customers with growing past due balances. Based on guidance provided by the SCC, will allow the Company was able to forgo a formal non-gas rate increaseapply the full amount to eligible customer accounts during the second and third fiscal quarters of fiscal 2021. On October 28, 2021, Roanoke Gas received notification from the SCC that its application at this time.
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.
Investments - Under the provisions of ASC 323, Investments - Equity Method and Joint Ventures, the Company is required to evaluate its investment in the LLC to determine if the fair value of the investments are below the carrying amount and if this decline in fair value is considered other-than-temporary. If the results of the evaluation indicate that the decline in fair value is other-than-temporary, then the recognition of an impairment is required. The following events or circumstances would indicate the potential of an other-than-temporary decline in the fair value of the investment in the LLC:
• a prolonged period of time that the fair value is below the investor’s carrying value;
• the current expected financial performance is significantly worse than anticipated when the investor originally invested in the investee;
• adverse regulatory action is expected to substantially reduce the investee’s product demand or profitability;
• the investee has lost significant customers or suppliers with no immediate prospects for replacement;
• the investee’s discounted or undiscounted cash flows are below the investor’s carrying amount; and
• the investee’s industry is declining and significantly lags the performance of the economy as a whole.
The determination of fair value of the Company's investment in the LLC is a significant estimate. Management has conducted quarterly evaluations of its investment in the LLC, with the assistance of a valuation specialist, to determine the fair value utilizing an income approach and probability scenarios of discounted cash flows. In conducting these evaluations, management made a variety of assumptions that it believes to be reasonable. Variations in many of these assumptions could have a significant impact on the calculation of the fair value and the resulting level of impairment recorded. Furthermore, these assumptions are based on the facts and circumstances at the date of the evaluations and are subject to change. See the Equity Investment in Mountain Valley Pipeline section for additional information regarding the LLC valuation and impairment.
Regulatory accounting
- The Company’s regulated operations follow the accounting and reporting requirements ofIf, 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-down of the COVID asset and deferred R&D tax credit study costs are consistent with the provisions of ASC 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 may beis 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 WNA payable. At the end of each WNA year, the Company will refundrefunds excess revenue collected for weather that was colder than the 30-year average or bill the customerbills customers for revenue short-fall forresulting from weather that was warmer than normal. As required under the provisions of FASB ASC No. 980,Regulated Operations, the Company recognizes billed revenue related to the 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 estimated revenue for estimated natural gas delivered to customers but not yet billed during the accounting period based on weather duringperiod. The following month, the periodunbilled estimate is reversed, the actual usage is billed and current and historical data.a new unbilled estimate is calculated. The consolidated financial statements include unbilled revenue of $965,683$1,585,062 and $1,004,061$1,191,227 as of September 30, 20172022 and 2016,2021, respectively.
Under the provisions of ASU 2014-09, Revenue from Contracts with Customers, the Company recognizes revenues when natural gas is delivered to customers (the performance obligation) based on SCC approved tariff rates (the transaction price). The Company recognizes revenue through both billed and unbilled customer usage. The Company also recognizes revenue through ARPs, including the WNA.
Allowance for Doubtful Accounts
Pension and Postretirement Benefits
- The Company offers aIn selecting the discount rate to be used in determining the benefit liability, the Company utilized the Citigroup yield curvesFTSE Pension Discount Curve, which incorporateincorporates 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 3.72%5.15% and 3.69%5.16%, respectively, for valuing its pension plan liability and postretirement plan liability at September 30, 2017.2022. These discount rates increased overrepresent an increase from the prior year by 0.30%2.73% and 0.36%, respectively.2.70% rates used for valuing the corresponding liabilities at September 30, 2021. The riseincrease in discount rates corresponds to the discount rate is evidenced bymarket reactions to the inflationary pressures on the current financial environment resulting from labor shortages and supply chain issues, among other factors. The yield on the 30-year Treasury rate, which increased from 2.32%2.08% last year to 2.86%. However, corporate3.79% at September 30, 2022. Corporate bond rates increased but toexperienced a lesser degree indicating thatlarger increase as credit spreads among high quality investments narrowed resulting in a smaller discount rate increase. This increaseappear to have widened. The rise in the discount rates was the primary driverfactor in the reduction of the accumulated benefit obligation onobligations 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-2021 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 in fiscal 2021. Each of these strategies have served to limit liability growth and reduce volatility.
The riseCompany also has focused on its asset investment strategy. With the soft freeze of both the pension and postretirement plans, future liability growth associated with participant service and compensation has been limited. Under 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 2022. The remaining 61% of the 2022 liability is set subject to variability due to changes in the discount rate forand mortality adjustments. Since January 2017 when the pension plan nearly offsetfroze access to new employees, the increaseasset 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 liabilities associatedsecurities with additional credited service and salary increases resulting in small increases in botha duration that corresponds to the accumulated benefit obligation and the projected benefit obligation. The Company used the RP-2014 Mortality Table, adjusted to 2006, with generational mortality improvements under Projection Scale MP-2016 for the current year valuation.
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. During fiscal 2022, the postretirement plan assets decreased by $3.7 million and liabilities decreased by $4.4 million. The funded status for the postretirement plan was 98% and 95% as of September 30, 2022 and 2021, respectively. 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 by $3,143,000 and $2,406,000, respectively. The combination of higher asset totals and higher discount rate also served to reduce pension and postretirement expense in fiscal 2018.
| Funded status - September 30, 2017 | Pension | Postretirement | Total | ||||||||
| Benefit Obligation | $ | 29,657,347 | $ | 17,666,812 | $ | 47,324,159 | |||||
| Fair value of assets | 26,418,671 | 12,691,162 | 39,109,833 | ||||||||
| Funded status | $ | (3,238,676 | ) | $ | (4,975,650 | ) | $ | (8,214,326 | ) | ||
| Funded status - September 30, 2016 | Pension | Postretirement | Total | ||||||||
| Benefit Obligation | $ | 29,494,950 | $ | 18,504,710 | $ | 47,999,660 | |||||
| Fair value of assets | 23,113,057 | 11,122,783 | 34,235,840 | ||||||||
| Funded status | $ | (6,381,893 | ) | $ | (7,381,927 | ) | $ | (13,763,820 | ) | ||
Funded status - September 30, 2022 | Pension | Postretirement | Total | |||||||||
Benefit Obligation | $ | 27,268,456 | $ | 12,416,546 | $ | 39,685,002 | ||||||
Fair value of assets | 28,017,797 | 12,138,119 | 40,155,916 | |||||||||
Funded status | $ | 749,341 | $ | (278,427 | ) | $ | 470,914 | |||||
Funded status - September 30, 2021 | Pension | Postretirement | Total | |||||||||
Benefit Obligation | $ | 37,654,468 | $ | 16,796,849 | $ | 54,451,317 | ||||||
Fair value of assets | 38,914,107 | 15,882,342 | 54,796,449 | |||||||||
Funded status | $ | 1,259,639 | $ | (914,507 | ) | $ | 345,132 | |||||
The variability in interest rates and investment returns create the potential for volatility in the Company's benefit plan liabilities, asset values, funded status and expense. Increasing interest rates would serve to reduce the benefit liabilities but may negatively impact returns on fixed income investments in the short-term, while a decline in interest rates would increase benefit liabilities and provide a short-term boost to fixed income returns. Equity
Management estimates that under the provisions of HATFA, the Company will have no minimum funding requirements next year. Although HATFA and MAP-21 allowFurthermore, the Company some funding relief, management expectscurrently does not expect to continue its pension funding plan by contributing at least the minimum annual pension contribution requirement or its expense level for subsequent years. The Company currently expects to contribute approximately $1,600,000make contributions to its pension plan and $600,000 to its postretirement plan in fiscal 2018 with a continuing goal2023 due to improve both plans' funded status.other financing considerations. The Company will continue to evaluate its benefit plan funding levels in light of funding requirements
The following schedule reflects the sensitivity of pension costs to changes in certain actuarial assumptions, assuming that the other components of the calculation remain constant.
| Actuarial Assumptions - Pension Plan | Change in Assumption | Increase in Pension Cost | Increase in Projected Benefit Obligation | |||||||
| Discount rate | -0.25 | % | $ | 123,000 | $ | 1,225,000 | ||||
| Rate of return on plan assets | -0.25 | % | 66,000 | N/A | ||||||
| Rate of increase in compensation | 0.25 | % | 53,000 | 292,000 | ||||||
Actuarial Assumptions - Pension Plan | Change in Assumption | Increase in Pension Cost | Increase in Projected Benefit Obligation | |||||||||
Discount rate | -0.25 | % | $ | 90,000 | $ | 888,000 | ||||||
Rate of return on plan assets | -0.25 | % | 68,000 | N/A | ||||||||
Rate of increase in compensation | 0.25 | % | 33,000 | 153,000 | ||||||||
The following schedule reflects the sensitivity of postretirement benefit costs from changes in certain actuarial assumptions, while the other components of the calculation remain constant.
| Actuarial Assumptions - Postretirement Plan | Change in Assumption | Increase in Postretirement Benefit Cost | Increase in Accumulated Postretirement Benefit Obligation | |||||||
| Discount rate | -0.25 | % | $ | 1,000 | $ | 747,000 | ||||
| Rate of return on plan assets | -0.25 | % | 29,000 | N/A | ||||||
| Medical claim cost increase | 0.25 | % | 45,000 | 723,000 | ||||||
Actuarial Assumptions - Postretirement Plan | Change in Assumption | Increase (Decrease) in Postretirement Benefit Cost | Increase in Accumulated Postretirement Benefit Obligation | |||||||||
Discount rate | -0.25 | % | $ | (19,000 | ) | $ | 378,000 | |||||
Rate of return on plan assets | -0.25 | % | 39,000 | N/A | ||||||||
Medical claim cost increase | 0.25 | % | 22,000 | 371,000 | ||||||||
Derivatives
- The Company may hedge certain risks incurred in its operation through the use of derivative instruments. The Company applies the requirements ofItem 7A.Quantitative and liabilities shall be adjusted for the effect of a change in tax lawsQualitative Disclosures About Market Risk.
Not applicable.
Item 8.Financial Statements and rates and the effect of such change shall be included in income from continuing operations for the period that includes the date of enactment. If lower federal corporate tax rates are passed, deferred income taxes at the date of enactment would be reduced and the net benefit or expense would flow through income tax expense. However, for Roanoke Gas, any adjustment to deferred taxes would not be reflected in the income statement. Instead, under the requirements of regulatory accounting, those excess deferred taxes would be reclassified to a regulatory liability to be refunded to the utility's customers, as the Company's non gas rates provided for the recovery of income taxes at a federal tax rate of 34%Supplementary Data. As of September 30, 2017, the Company has a net deferred tax liability of approximately $23,100,000 of which Roanoke Gas represented approximately $23,900,000 of that balance while the unregulated operations of Resources had a net deferred tax asset of $800,000. If a corporate tax rate decrease becomes law, then for every one percent decrease in the federal corporate tax rate, approximately $600,000 would be transferred to a regulatory liability and $20,000 would be reflected as additional income tax expense in comprehensive income. Other proposed tax law changes may have impacts, both favorable or unfavorable, to the Company's tax expense and deferred tax balances. No adjustment will be made to deferred taxes or income tax expense until such time as any proposed tax legislation is signed into law.
RGC Resources, Inc.
Consolidated Financial Statements
for the Years Ended September 30, 2017, 2016
and Report of Independent
Registered Public Accounting Firm
TABLE OF CONTENTS
Page | |
Consolidated Financial Statements for the Years Ended September 30, | |
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, 20172022 and 2016,2021, and the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the years in the three-yeartwo-year period ended September 30, 2017. RGC Resources, Inc.’s management is responsible2022, 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, 2022 and 2021, and the results of its operations and its cash flows for theseeach of the years in the two-year period ended September 30, 2022, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements.statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on thesethe Company’s consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).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. Anmisstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform an audit includesof 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 supportingregarding the amounts and disclosures in the financial statements. An auditOur audits also includes assessingincluded evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statement presentation.statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements referredthat was communicated or required to above present fairly, in allbe communicated to the audit committee and that: (1) relate to accounts or disclosures that are material respects,to the financial positionstatements and (2) involved our especially challenging, subjective, or complex judgments. The communication of RGC Resources, Inc.critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and Subsidiarieswe are not, by communicating the critical audit matter below, providing separate opinions on the critical audit matter or on the accounts or disclosures to which it relates.
Valuation of Equity Method Investment in Mountain Valley Pipeline, LLC (“MVP”)
Description of the matter
As of September 30, 2022, the Company has investments in unconsolidated affiliates of $13.8 million. The majority of this amount, $13.7 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 carrying value exceeded the fair value at September 30, 2022. Accordingly, an impairment loss of $55.1 million was recorded reducing the investment in unconsolidated affiliates from $68.9 million to $13.8 million as of September 30, 2017 and 2016, and the consolidated results2022. The Company contracted a third party valuation specialist to perform a valuation of its operations and its cash flows for each of the years in the three-year period ended September 30, 2017, in conformity with accounting principles generally accepted in the United States of America.
Auditing management’s evaluation of Sponsoring Organizationsimpairment of the Treadway Commission (COSO),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 and probability estimates employed. 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 report dated December 8, 2017 expressedAudit
We obtained an unqualified opinion.
Audit procedures related to discounted future cash flows included, among others, procedures to evaluate cash flows considered in the valuation. Audit procedures related to probability estimates included assessment of management's considerations in development of these estimates. Additionally, 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.
| /s/ Brown Edwards & Company, L.L.P | |
 | |
CERTIFIED PUBLIC ACCOUNTANTS | |
We have served as the Company's auditor since 2006.
Roanoke, Virginia
December 2, 2022
CONSOLIDATED BALANCE SHEETS
AS OF SEPTEMBERSeptember 30, 20172022 AND 2016
2022 | 2021 | |||||||
ASSETS | ||||||||
CURRENT ASSETS: | ||||||||
Cash and cash equivalents | $ | 4,898,914 | $ | 1,518,317 | ||||
Accounts receivable, net | 5,353,270 | 4,949,900 | ||||||
Materials and supplies | 1,228,554 | 1,031,666 | ||||||
Gas in storage | 16,916,651 | 7,867,470 | ||||||
Prepaid income taxes | 3,087,755 | 3,104,950 | ||||||
Regulatory assets | 1,877,468 | 5,656,453 | ||||||
Interest rate swaps | 1,218,211 | — | ||||||
Other | 967,496 | 1,015,099 | ||||||
Total current assets | 35,548,319 | 25,143,855 | ||||||
UTILITY PROPERTY: | ||||||||
In service | 290,940,683 | 272,382,539 | ||||||
Accumulated depreciation and amortization | (80,242,946 | ) | (76,038,433 | ) | ||||
In service, net | 210,697,737 | 196,344,106 | ||||||
Construction work in progress | 19,163,337 | 15,305,578 | ||||||
Utility property, net | 229,861,074 | 211,649,684 | ||||||
OTHER NON-CURRENT ASSETS: | ||||||||
Regulatory assets | 5,446,547 | 6,769,759 | ||||||
Investment in unconsolidated affiliates | 13,773,075 | 64,867,319 | ||||||
Benefit plan assets | 749,341 | 1,259,639 | ||||||
Deferred income taxes | 1,057,079 | — | ||||||
Interest rate swaps | 3,580,256 | — | ||||||
Other | 293,552 | 418,937 | ||||||
Total other non-current assets | 24,899,850 | 73,315,654 | ||||||
TOTAL ASSETS | $ | 290,309,243 | $ | 310,109,193 | ||||
(Continued)
| 2017 | 2016 | ||||||
| ASSETS | |||||||
| CURRENT ASSETS: | |||||||
| Cash and cash equivalents | $ | 69,640 | $ | 643,252 | |||
| Accounts receivable, net | 3,492,703 | 3,478,983 | |||||
| Materials and supplies | 1,021,191 | 824,139 | |||||
| Gas in storage | 7,701,894 | 7,436,785 | |||||
| Prepaid income taxes | 1,796,825 | 1,550,836 | |||||
| Interest rate swap | 26,777 | — | |||||
| Other | 1,576,574 | 1,548,329 | |||||
| Total current assets | 15,685,604 | 15,482,324 | |||||
| UTILITY PROPERTY: | |||||||
| In service | 204,223,714 | 185,577,286 | |||||
| Accumulated depreciation and amortization | (59,765,987 | ) | (56,156,287 | ) | |||
| In service, net | 144,457,727 | 129,420,999 | |||||
| Construction work in progress | 3,470,244 | 2,707,139 | |||||
| Utility plant, net | 147,927,971 | 132,128,138 | |||||
| OTHER ASSETS: | |||||||
| Regulatory assets | 11,796,260 | 14,332,451 | |||||
| Investment in unconsolidated affiliate | 7,445,106 | 3,496,404 | |||||
| Interest rate swap | 90,066 | — | |||||
| Other | 190,064 | 113,532 | |||||
| Total other assets | 19,521,496 | 17,942,387 | |||||
| TOTAL ASSETS | $ | 183,135,071 | $ | 165,552,849 | |||
RGC RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF SEPTEMBERSeptember 30, 20172022 AND 2016
2022 | 2021 | |||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
CURRENT LIABILITIES: | ||||||||
Current maturities of long-term debt | $ | 1,300,000 | $ | 7,000,000 | ||||
Dividends payable | 1,915,317 | 1,549,841 | ||||||
Accounts payable | 8,600,919 | 7,729,707 | ||||||
Capital contributions payable | 804,506 | 2,140,637 | ||||||
Customer credit balances | 1,400,770 | 1,539,680 | ||||||
Customer deposits | 1,457,610 | 1,571,342 | ||||||
Accrued expenses | 3,668,122 | 3,819,977 | ||||||
Interest rate swaps | — | 332,389 | ||||||
Regulatory liabilities | 3,168,066 | 329,959 | ||||||
Total current liabilities | 22,315,310 | 26,013,532 | ||||||
LONG-TERM DEBT: | ||||||||
Notes payable | 135,971,200 | 116,110,200 | ||||||
Line-of-credit | — | 17,628,897 | ||||||
Less unamortized debt issuance costs | (275,911 | ) | (267,670 | ) | ||||
Long-term debt, net | 135,695,289 | 133,471,427 | ||||||
DEFERRED CREDITS AND OTHER NON-CURRENT LIABILITIES: | ||||||||
Interest rate swaps | — | 863,694 | ||||||
Asset retirement obligations | 10,204,079 | 7,628,958 | ||||||
Regulatory cost of retirement obligations | 12,277,796 | 13,640,567 | ||||||
Benefit plan liabilities | 337,535 | 949,851 | ||||||
Deferred income taxes | 3,165,454 | 14,948,213 | ||||||
Regulatory liabilities | 13,223,124 | 12,891,242 | ||||||
Total deferred credits and other non-current liabilities | 39,207,988 | 50,922,525 | ||||||
COMMITMENTS AND CONTINGENCIES (Note 12) | ||||||||
CAPITALIZATION: | ||||||||
Stockholders’ Equity: | ||||||||
Common Stock, $5 par value; authorized 20,000,000 shares; issued and outstanding 9,820,535 and 8,375,092 shares in 2022 and 2021, respectively | 49,102,675 | 41,875,460 | ||||||
Preferred stock, no par; authorized 5,000,000 shares; no shares issued and outstanding in 2022 and 2021 | — | — | ||||||
Capital in excess of par value | 41,479,459 | 19,705,387 | ||||||
Retained earnings | 544,158 | 39,656,296 | ||||||
Accumulated other comprehensive income (loss) | 1,964,364 | (1,535,434 | ) | |||||
Total stockholders’ equity | 93,090,656 | 99,701,709 | ||||||
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY | $ | 290,309,243 | $ | 310,109,193 | ||||
| 2017 | 2016 | ||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||
| CURRENT LIABILITIES: | |||||||
| Line-of-credit | $ | — | $ | 14,556,785 | |||
| Dividends payable | 1,050,281 | 970,244 | |||||
| Accounts payable | 5,122,899 | 5,345,575 | |||||
| Capital contributions payable | 1,055,504 | 287,794 | |||||
| Customer credit balances | 1,220,578 | 1,605,608 | |||||
| Customer deposits | 1,471,960 | 1,627,105 | |||||
| Accrued expenses | 3,006,936 | 3,194,255 | |||||
| Over-recovery of gas costs | 1,438,074 | 909,687 | |||||
| Total current liabilities | 14,366,232 | 28,497,053 | |||||
| LONG-TERM DEBT: | |||||||
| Notes payable | 43,812,200 | 33,896,200 | |||||
| Line-of-credit | 17,791,760 | — | |||||
| Less unamortized debt issuance costs | (291,949 | ) | (260,149 | ) | |||
| Long-term debt net of unamortized debt issuance costs | 61,312,011 | 33,636,051 | |||||
| DEFERRED CREDITS AND OTHER LIABILITIES: | |||||||
| Asset retirement obligations | 6,069,993 | 5,682,556 | |||||
| Regulatory cost of retirement obligations | 10,055,189 | 9,348,443 | |||||
| Benefit plan liabilities | 8,214,326 | 13,763,820 | |||||
| Deferred income taxes | 23,076,848 | 18,957,854 | |||||
| Total deferred credits and other liabilities | 47,416,356 | 47,752,673 | |||||
| COMMITMENTS AND CONTINGENCIES (Note 11) | |||||||
| CAPITALIZATION: | |||||||
| Stockholders’ Equity: | |||||||
| Common Stock, $5 par value; authorized 10,000,000 shares; issued and outstanding 7,240,846 and 7,182,434 shares in 2017 and 2016, respectively | 36,204,230 | 23,941,445 | |||||
| Preferred stock, no par; authorized 5,000,000 shares; no shares issued and outstanding in 2017 and 2016 | — | — | |||||
| Capital in excess of par value | 292,485 | 9,509,548 | |||||
| Retained earnings | 24,746,021 | 24,713,310 | |||||
| Accumulated other comprehensive loss | (1,202,264 | ) | (2,497,231 | ) | |||
| Total stockholders’ equity | 60,040,472 | 55,667,072 | |||||
| TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY | $ | 183,135,071 | $ | 165,552,849 | |||
See notes to consolidated financial statements.
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED SEPTEMBERSeptember 30, 2017, 20162022 AND 2015
2022 | 2021 | |||||||
OPERATING REVENUES: | ||||||||
Gas utility | $ | 84,035,644 | $ | 75,045,103 | ||||
Non utility | 129,578 | 129,676 | ||||||
Total operating revenues | 84,165,222 | 75,174,779 | ||||||
OPERATING EXPENSES: | ||||||||
Cost of gas - utility | 42,496,055 | 35,179,842 | ||||||
Cost of sales - non utility | 29,126 | 25,557 | ||||||
Operations and maintenance | 15,489,240 | 14,476,355 | ||||||
General taxes | 2,285,203 | 2,290,096 | ||||||
Depreciation and amortization | 8,948,923 | 8,424,620 | ||||||
Total operating expenses | 69,248,547 | 60,396,470 | ||||||
OPERATING INCOME | 14,916,675 | 14,778,309 | ||||||
Equity in earnings of unconsolidated affiliate | 73,327 | 1,667,554 | ||||||
Impairment of unconsolidated affiliates | (55,092,303 | ) | — | |||||
Other income, net | 1,456,983 | 912,146 | ||||||
Interest expense | 4,497,929 | 4,051,885 | ||||||
INCOME (LOSS) BEFORE INCOME TAXES | (43,143,247 | ) | 13,306,124 | |||||
INCOME TAX EXPENSE (BENEFIT) | (11,410,645 | ) | 3,204,062 | |||||
NET INCOME (LOSS) | $ | (31,732,602 | ) | $ | 10,102,062 | |||
EARNINGS (LOSS) PER COMMON SHARE: | ||||||||
Basic | $ | (3.48 | ) | $ | 1.22 | |||
Diluted | $ | (3.48 | ) | $ | 1.22 | |||
WEIGHTED AVERAGE SHARES OUTSTANDING: | ||||||||
Basic | 9,122,678 | 8,251,802 | ||||||
Diluted | 9,122,678 | 8,264,904 | ||||||
| 2017 | 2016 | 2015 | |||||||||
| OPERATING REVENUES: | |||||||||||
| Gas utilities | $ | 61,252,015 | $ | 58,079,990 | $ | 67,094,290 | |||||
| Other | 1,044,855 | 983,301 | 1,095,317 | ||||||||
| Total operating revenues | 62,296,870 | 59,063,291 | 68,189,607 | ||||||||
| COST OF SALES: | |||||||||||
| Gas utilities | 28,919,625 | 27,009,330 | 37,437,315 | ||||||||
| Other | 568,088 | 489,047 | 545,859 | ||||||||
| Total cost of sales | 29,487,713 | 27,498,377 | 37,983,174 | ||||||||
| GROSS MARGIN | 32,809,157 | 31,564,914 | 30,206,433 | ||||||||
| OTHER OPERATING EXPENSES: | |||||||||||
| Operations and maintenance | 13,100,041 | 13,098,086 | 13,486,885 | ||||||||
| General taxes | 1,786,070 | 1,663,126 | 1,606,421 | ||||||||
| Depreciation and amortization | 6,256,737 | 5,591,610 | 5,106,935 | ||||||||
| Total other operating expenses | 21,142,848 | 20,352,822 | 20,200,241 | ||||||||
| OPERATING INCOME | 11,666,309 | 11,212,092 | 10,006,192 | ||||||||
| Equity in earnings of unconsolidated affiliate | 421,646 | 152,864 | — | ||||||||
| Other expense, net | 132,446 | 255,585 | 228,796 | ||||||||
| Interest expense | 1,917,254 | 1,636,321 | 1,512,419 | ||||||||
| INCOME BEFORE INCOME TAXES | 10,038,255 | 9,473,050 | 8,264,977 | ||||||||
| INCOME TAX EXPENSE | 3,805,390 | 3,666,184 | 3,170,562 | ||||||||
| NET INCOME | $ | 6,232,865 | $ | 5,806,866 | $ | 5,094,415 | |||||
| EARNINGS PER COMMON SHARE: | |||||||||||
| Basic | $ | 0.86 | $ | 0.81 | $ | 0.72 | |||||
| Diluted | $ | 0.86 | $ | 0.81 | $ | 0.72 | |||||
| WEIGHTED AVERAGE SHARES OUTSTANDING: | |||||||||||
| Basic | 7,218,686 | 7,149,906 | 7,092,315 | ||||||||
| Diluted | 7,256,046 | 7,159,763 | 7,097,514 | ||||||||
See notes to consolidated financial statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
YEARS ENDED SEPTEMBERSeptember 30, 2017, 20162022 AND 2015
2022 | 2021 | |||||||
NET INCOME (LOSS) | $ | (31,732,602 | ) | $ | 10,102,062 | |||
Other comprehensive income (loss), net of tax: | ||||||||
Interest rate swaps | 4,451,551 | 763,003 | ||||||
Defined benefit plans | (951,753 | ) | 1,149,507 | |||||
OTHER COMPREHENSIVE INCOME, NET OF TAX | 3,499,798 | 1,912,510 | ||||||
COMPREHENSIVE INCOME (LOSS) | $ | (28,232,804 | ) | $ | 12,014,572 | |||
| 2017 | 2016 | 2015 | |||||||||
| NET INCOME | $ | 6,232,865 | $ | 5,806,866 | $ | 5,094,415 | |||||
| Other comprehensive income, net of tax: | |||||||||||
| Interest rate swaps | 72,489 | — | — | ||||||||
| Defined benefit plans | 1,222,478 | (210,686 | ) | (1,147,219 | ) | ||||||
| OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX | 1,294,967 | (210,686 | ) | (1,147,219 | ) | ||||||
| COMPREHENSIVE INCOME | $ | 7,527,832 | $ | 5,596,180 | $ | 3,947,196 | |||||
See notes to consolidated financial statements.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’STOCKHOLDERS’ EQUITY
YEARS ENDED SEPTEMBERSeptember 30, 2017, 20162022 AND 20152021
Accumulated | ||||||||||||||||||||
Capital in | Other | Total | ||||||||||||||||||
Common | Excess of | Retained | Comprehensive | Stockholders’ | ||||||||||||||||
Stock | Par Value | Earnings | Income (Loss) | Equity | ||||||||||||||||
Balance - September 30, 2020 | $ | 40,800,290 | $ | 15,847,121 | $ | 35,688,510 | $ | (3,447,944 | ) | $ | 88,887,977 | |||||||||
Net income | — | — | 10,102,062 | — | 10,102,062 | |||||||||||||||
Other comprehensive income | — | — | — | 1,912,510 | 1,912,510 | |||||||||||||||
Exercise of stock options (9,250 shares) | 46,250 | 91,551 | — | — | 137,801 | |||||||||||||||
Stock option grants | — | 11,100 | — | — | 11,100 | |||||||||||||||
Cash dividends declared ($0.74 per share) | — | — | (6,134,276 | ) | — | (6,134,276 | ) | |||||||||||||
Issuance costs | — | (116,926 | ) | — | — | (116,926 | ) | |||||||||||||
Issuance of common stock (205,784 shares) | 1,028,920 | 3,872,541 | — | — | 4,901,461 | |||||||||||||||
Balance - September 30, 2021 | $ | 41,875,460 | $ | 19,705,387 | $ | 39,656,296 | $ | (1,535,434 | ) | $ | 99,701,709 | |||||||||
Net loss | — | — | (31,732,602 | ) | — | (31,732,602 | ) | |||||||||||||
Other comprehensive income | — | — | — | 3,499,798 | 3,499,798 | |||||||||||||||
Exercise of stock options (8,750 shares) | 43,750 | 83,064 | — | — | 126,814 | |||||||||||||||
Stock option grants | — | 16,330 | — | — | 16,330 | |||||||||||||||
Cash dividends declared ($0.78 per share) | — | — | (7,379,536 | ) | — | (7,379,536 | ) | |||||||||||||
Issuance costs | — | (54,175 | ) | — | — | (54,175 | ) | |||||||||||||
Issuance of common stock (1,436,693 shares) | 7,183,465 | 21,728,853 | — | — | 28,912,318 | |||||||||||||||
Balance - September 30, 2022 | $ | 49,102,675 | $ | 41,479,459 | $ | 544,158 | $ | 1,964,364 | $ | 93,090,656 | ||||||||||
Common Stock | Capital in Excess of Par Value | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Total Stockholders’ Equity | |||||||||||||||
| Balance - September 30, 2014 | $ | 23,601,890 | $ | 8,237,228 | $ | 21,321,055 | $ | (1,139,326 | ) | $ | 52,020,847 | ||||||||
| Net income | — | — | 5,094,415 | — | 5,094,415 | ||||||||||||||
| Other comprehensive loss | — | — | — | (1,147,219 | ) | (1,147,219 | ) | ||||||||||||
| Exercise of stock options (3,900 shares) | 13,000 | 36,366 | — | — | 49,366 | ||||||||||||||
| Stock option grants | — | 83,640 | — | — | 83,640 | ||||||||||||||
| Cash dividends declared ($0.51 per share) | — | — | (3,643,093 | ) | — | (3,643,093 | ) | ||||||||||||
| Issuance of common stock (27,780 shares) | 92,600 | 290,435 | — | — | 383,035 | ||||||||||||||
| Balance - September 30, 2015 | $ | 23,707,490 | $ | 8,647,669 | $ | 22,772,377 | $ | (2,286,545 | ) | $ | 52,840,991 | ||||||||
| Net income | — | — | 5,806,866 | — | 5,806,866 | ||||||||||||||
| Other comprehensive loss | — | — | — | (210,686 | ) | (210,686 | ) | ||||||||||||
| Exercise of stock options (3,300 shares) | 11,000 | 30,762 | — | — | 41,762 | ||||||||||||||
| Stock option grants | — | 64,640 | — | — | 64,640 | ||||||||||||||
| Cash dividends declared ($0.54 per share) | — | — | (3,865,933 | ) | — | (3,865,933 | ) | ||||||||||||
| Issuance of common stock (66,887 shares) | 222,955 | 766,477 | — | — | 989,432 | ||||||||||||||
| Balance - September 30, 2016 | $ | 23,941,445 | $ | 9,509,548 | $ | 24,713,310 | $ | (2,497,231 | ) | $ | 55,667,072 | ||||||||
| Net income | — | — | 6,232,865 | — | 6,232,865 | ||||||||||||||
| Other comprehensive income | — | — | — | 1,294,967 | 1,294,967 | ||||||||||||||
| Exercise of stock options (11,225 shares) | 50,250 | 91,991 | — | — | 142,241 | ||||||||||||||
| Stock option grants | — | 73,780 | — | — | 73,780 | ||||||||||||||
| Cash dividends declared ($0.58 per share) | — | — | (4,195,910 | ) | — | (4,195,910 | ) | ||||||||||||
| Stock split | 12,029,790 | (10,025,546 | ) | (2,004,244 | ) | — | — | ||||||||||||
| Issuance costs | — | (96,508 | ) | — | — | (96,508 | ) | ||||||||||||
| Issuance of common stock (47,187 shares) | 182,745 | 739,220 | — | — | 921,965 | ||||||||||||||
| Balance - September 30, 2017 | $ | 36,204,230 | $ | 292,485 | $ | 24,746,021 | $ | (1,202,264 | ) | $ | 60,040,472 | ||||||||
See notes to consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED SEPTEMBERSeptember 30, 2017, 20162022 AND 20152021
2022 | 2021 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||
Net income (loss) | $ | (31,732,602 | ) | $ | 10,102,062 | |||
Adjustments to reconcile net income to net cash provided by operations: | ||||||||
Depreciation and amortization | 9,182,751 | 8,669,977 | ||||||
Cost of retirement of utility property, net | (630,262 | ) | (545,443 | ) | ||||
Stock option grants | 16,330 | 11,100 | ||||||
Equity in earnings of unconsolidated affiliate | (73,327 | ) | (1,667,554 | ) | ||||
Impairment of unconsolidated affiliates | 55,092,303 | — | ||||||
Allowance for funds used during construction | (75,154 | ) | (55,981 | ) | ||||
Deferred income taxes | (14,258,294 | ) | 106,188 | |||||
Other noncash items, net | 317,169 | (243,496 | ) | |||||
Changes in assets and liabilities which provided (used) cash: | ||||||||
Accounts receivable and customer deposits, net | (646,362 | ) | (1,124,860 | ) | ||||
Inventories and gas in storage | �� | (9,246,069 | ) | (2,163,184 | ) | |||
Regulatory and other assets | 3,949,270 | (6,190,720 | ) | |||||
Accounts payable, customer credit balances and accrued expenses, net | 310,700 | 2,862,861 | ||||||
Regulatory liabilities | 3,345,223 | 1,807,158 | ||||||
Total adjustments | 47,284,278 | 1,466,046 | ||||||
Net cash provided by operating activities | 15,551,676 | 11,568,108 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||
Expenditures for utility property | (25,461,000 | ) | (19,967,567 | ) | ||||
Investment in unconsolidated affiliates | (5,260,863 | ) | (6,028,760 | ) | ||||
Proceeds from disposal of utility property | 105,985 | 147,090 | ||||||
Net cash used in investing activities | (30,615,878 | ) | (25,849,237 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||
Borrowings under line-of-credit | 36,871,007 | 47,043,566 | ||||||
Repayments under line-of-credit | (54,499,904 | ) | (38,558,275 | ) | ||||
Proceeds from issuance of unsecured notes | 39,286,000 | 8,135,000 | ||||||
Retirement of notes payable | (25,125,000 | ) | — | |||||
Debt issuance expenses | (58,201 | ) | (21,545 | ) | ||||
Proceeds from issuance of stock | 28,984,957 | 4,922,337 | ||||||
Cash dividends paid | (7,014,060 | ) | (6,012,703 | ) | ||||
Net cash provided by financing activities | 18,444,799 | 15,508,380 | ||||||
NET INCREASE IN CASH AND CASH EQUIVALENTS | 3,380,597 | 1,227,251 | ||||||
BEGINNING CASH AND CASH EQUIVALENTS | 1,518,317 | 291,066 | ||||||
ENDING CASH AND CASH EQUIVALENTS | $ | 4,898,914 | $ | 1,518,317 | ||||
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | ||||||||
Cash paid during the year for: | ||||||||
Interest | $ | 4,269,900 | $ | 3,886,747 | ||||
Income taxes | 2,290,000 | 3,063,083 | ||||||
| 2017 | 2016 | 2015 | |||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES: | |||||||||||
| Net income | $ | 6,232,865 | $ | 5,806,866 | $ | 5,094,415 | |||||
| Adjustments to reconcile net income to net cash provided by operations: | |||||||||||
| Depreciation and amortization | 6,378,368 | 5,709,525 | 5,219,893 | ||||||||
| Cost of retirement of utility plant, net | (354,744 | ) | (449,201 | ) | (406,731 | ) | |||||
| Stock option grants | 73,780 | 64,640 | 83,640 | ||||||||
| Equity in earnings of unconsolidated affiliate | (421,646 | ) | (152,864 | ) | — | ||||||
| Deferred income taxes | 3,325,379 | 4,466,954 | 2,416,841 | ||||||||
| Other noncash items, net | 203,743 | 197,298 | 105,815 | ||||||||
| Changes in assets and liabilities which provided (used) cash: | |||||||||||
| Accounts receivable and customer deposits, net | (191,386 | ) | (258,960 | ) | 638,917 | ||||||
| Inventories and gas in storage | (462,161 | ) | 867,682 | 3,168,056 | |||||||
| Over/under recovery of gas costs | 528,387 | (991,739 | ) | 2,082,257 | |||||||
| Other assets | (956,894 | ) | (398,864 | ) | (768,922 | ) | |||||
| Accounts payable, customer credit balances and accrued expenses, net | (1,374,713 | ) | 60,303 | (873,354 | ) | ||||||
| Total adjustments | 6,748,113 | 9,114,774 | 11,666,412 | ||||||||
| Net cash provided by operating activities | 12,980,978 | 14,921,640 | 16,760,827 | ||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES: | |||||||||||
| Expenditures for utility property | (20,750,181 | ) | (17,945,719 | ) | (13,780,356 | ) | |||||
| Investment in unconsolidated affiliate | (2,759,346 | ) | (3,055,746 | ) | — | ||||||
| Proceeds from disposal of utility property | 16,972 | 4,964 | 30,082 | ||||||||
| Net cash used in investing activities | (23,492,555 | ) | (20,996,501 | ) | (13,750,274 | ) | |||||
| CASH FLOWS FROM FINANCING ACTIVITIES: | |||||||||||
| Borrowings under line-of-credit | 42,569,303 | 38,310,326 | 34,698,924 | ||||||||
| Repayments under line-of-credit | (39,334,328 | ) | (33,094,539 | ) | (34,402,977 | ) | |||||
| Proceeds from issuance of unsecured notes | 9,916,000 | 3,396,200 | — | ||||||||
| Debt issuance expenses | (64,835 | ) | (101,619 | ) | — | ||||||
| Proceeds from issuance of stock | 967,698 | 1,031,194 | 432,401 | ||||||||
| Cash dividends paid | (4,115,873 | ) | (3,808,683 | ) | (3,603,424 | ) | |||||
| Net cash provided by (used in) financing activities | 9,937,965 | 5,732,879 | (2,875,076 | ) | |||||||
| NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | (573,612 | ) | (341,982 | ) | 135,477 | ||||||
| CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR | 643,252 | 985,234 | 849,757 | ||||||||
| CASH AND CASH EQUIVALENTS AT END OF YEAR | $ | 69,640 | $ | 643,252 | $ | 985,234 | |||||
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | |||||||||||
| Cash paid (refunded) during the year for: | |||||||||||
| Interest | $ | 1,734,178 | $ | 1,480,665 | $ | 1,002,462 | |||||
| Income taxes | 726,000 | (907,000 | ) | 1,266,573 | |||||||
See notes to consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBERSeptember 30, 2017, 20162022 AND 2015
1. | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
Principles of Consolidation
—RGC Resources, Inc. is an energy services company primarily engaged in the sale and distribution of natural gas. The consolidated financial statements include the accounts ofThe Company follows accounting and reporting standards established by the Financial Accounting Standards Board (“FASB”)FASB and the Securities and Exchange Commission (“SEC”).
Rate Regulated Basis of Accounting
—The Company’s regulated operations follow the accounting and reporting requirements ofRegulatory assets and liabilities included in the Company’s consolidated balance sheets as of September 30, 20172022 and 20162021 are as follows:
| September 30 | ||||||||
| 2017 | 2016 | |||||||
| Regulatory Assets: | ||||||||
| Current Assets: | ||||||||
| Accounts receivable: | ||||||||
| Accrued WNA revenues | $ | 248,840 | $ | 148,663 | ||||
| Other: | ||||||||
| Accrued pension and postretirement medical | 658,786 | 835,704 | ||||||
| Utility Property: | ||||||||
| In service: | ||||||||
| Other | 11,945 | 11,945 | ||||||
| Other Assets: | ||||||||
| Regulatory assets: | ||||||||
| Premium on early retirement of debt | 1,941,182 | 2,055,369 | ||||||
| Accrued pension and postretirement medical | 8,643,524 | 11,460,738 | ||||||
| Other | 1,211,554 | 816,344 | ||||||
| Total regulatory assets | $ | 12,715,831 | $ | 15,328,763 | ||||
| Regulatory Liabilities: | ||||||||
| Current Liabilities: | ||||||||
| Over-recovery of gas costs | $ | 1,438,074 | $ | 909,687 | ||||
| Accrued expenses: | ||||||||
| Over-recovery of SAVE Plan revenues | 215,514 | 238,694 | ||||||
| Deferred Credits and Other Liabilities: | ||||||||
| Asset retirement obligations | 6,069,993 | 5,682,556 | ||||||
| Regulatory cost of retirement obligations | 10,055,189 | 9,348,443 | ||||||
| Total regulatory liabilities | $ | 17,778,770 | $ | 16,179,380 | ||||
September 30 | ||||||||
2022 | 2021 | |||||||
Assets: | ||||||||
Current Assets: | ||||||||
Regulatory assets: | ||||||||
Accrued WNA revenues | $ | 193,518 | $ | 8,104 | ||||
Under-recovery of gas costs | 1,316,580 | 5,048,164 | ||||||
Under-recovery of SAVE Plan revenues | — | 305,502 | ||||||
Accrued pension and postretirement medical | 237,911 | 206,679 | ||||||
Other deferred expenses | 129,459 | 88,004 | ||||||
Total current | 1,877,468 | 5,656,453 | ||||||
Utility Property: | ||||||||
In service: | ||||||||
Other | 11,945 | 11,945 | ||||||
Construction work in progress: | ||||||||
AFUDC | 461,342 | �� | 386,189 | |||||
Other Non-Current Assets: | ||||||||
Regulatory assets: | ||||||||
Premium on early retirement of debt | 1,370,246 | 1,484,433 | ||||||
Accrued pension and postretirement medical | 3,894,561 | 5,154,713 | ||||||
Other deferred expenses | 181,740 | 130,613 | ||||||
Total non-current | 5,446,547 | 6,769,759 | ||||||
Total regulatory assets | $ | 7,797,302 | $ | 12,824,346 | ||||
Liabilities and Stockholders' Equity: | ||||||||
Current Liabilities: | ||||||||
Regulatory liabilities: | ||||||||
Over-recovery of SAVE Plan revenues | $ | 158,847 | $ | — | ||||
Deferred income taxes | 363,297 | 329,959 | ||||||
Supplier refunds | 2,484,992 | — | ||||||
Other deferred liabilities | 160,930 | — | ||||||
Total current | 3,168,066 | 329,959 | ||||||
Deferred Credits and Non-Current Other Liabilities: | ||||||||
Asset retirement obligations | 10,204,079 | 7,628,958 | ||||||
Regulatory cost of retirement obligations | 12,277,796 | 13,640,567 | ||||||
Regulatory liabilities: | ||||||||
Deferred income taxes | 13,193,006 | 12,891,242 | ||||||
Other | 30,118 | — | ||||||
Total non-current | $ | 35,704,999 | $ | 34,160,767 | ||||
Total regulatory liabilities | $ | 38,873,065 | $ | 34,490,726 | ||||
Amortization of $156,467 and $84,315 of regulatory assets for the years ended September 30, 2022 and 2021, respectively, is included in operations and maintenance expense on the consolidated statements of income. Amortization of $206,679 and $576,731 of regulatory assets for the years ended September 30, 2022 and 2021, respectively, is included in other income, net on the consolidated statements of income.
As of September 30, 2017,2022, the Company had regulatory assets in the amount of $12,703,886$7,785,357 on which the Company did not earn a return during the recovery period. These assets primarily pertain to the net funded position of the Company’s benefit plans related to its regulated operations. As such, the amortization period is not specifically defined.
Utility PlantProperty and Depreciation—Utility plantproperty 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 plantproperty 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 plantproperty is composed of the following major classes of assets:
| Years Ended September 30 | ||||||||
| 2017 | 2016 | |||||||
| Distribution and transmission | $ | 177,845,619 | $ | 160,354,300 | ||||
| LNG storage | 13,299,288 | 12,594,294 | ||||||
| General and miscellaneous | 13,078,807 | 12,628,692 | ||||||
| Total utility plant in service | $ | 204,223,714 | $ | 185,577,286 | ||||
September 30 | ||||||||
2022 | 2021 | |||||||
Distribution and transmission | $ | 259,253,559 | $ | 241,493,911 | ||||
LNG storage | 15,383,276 | 14,966,584 | ||||||
General and miscellaneous | 16,303,848 | 15,922,044 | ||||||
Total utility property in service | $ | 290,940,683 | $ | 272,382,539 | ||||
Provisions for depreciation are computed principally at composite straight-line rates over periods ranging from 5 to 76 years.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 Company completed its last depreciation study was completed and approved by the SCC staff in June 2014.fiscal 2019. The Company will complete a new depreciation study during fiscal 2024. The composite weighted-average depreciation rate realized using the most recently completed depreciation study was 3.29%3.28% for the fiscal yearyears ended September 30, 20172022 and 3.25% for the fiscal years ended September 30, 2016 and 2015.
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. RetirementThese 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. In fiscal 2022, the SCC approved the application of AFUDC on another infrastructure project during its construction phrase. This treatment allows capitalizing both the equity and debt financing costs during the construction phases. During fiscal 2021, the Company ceased recognizing AFUDC on the gate stations until such time as MVP is granted authorization to continue and construction activities resume of MVP and the gate stations. For the years ended September 30, 2022, and 2021, the Company capitalized $15,911 and $14,003 of debt financing costs and $59,243 and $41,978 of equity financing costs related to these projects, 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
—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 asset retirement obligationARO 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. In 2017,2022, the Company increased its asset retirement obligation to reflect revisions to the estimated cash flows for asset retirements.retirements due to increasing costs.
The following is a summary of the asset retirement obligation:
Years Ended September 30 | ||||||||
2022 | 2021 | |||||||
Beginning balance | $ | 7,628,958 | $ | 7,180,982 | ||||
Liabilities incurred | 236,926 | 214,533 | ||||||
Liabilities settled | (131,763 | ) | (160,064 | ) | ||||
Accretion | 397,692 | 393,507 | ||||||
Revisions to estimated cash flows | 2,072,266 | — | ||||||
Ending balance | $ | 10,204,079 | $ | 7,628,958 | ||||
| Years Ended September 30 | ||||||||
| 2017 | 2016 | |||||||
| Beginning balance | $ | 5,682,556 | $ | 5,295,868 | ||||
| Liabilities incurred | 65,556 | 85,263 | ||||||
| Liabilities settled | (137,304 | ) | (176,090 | ) | ||||
| Accretion | 312,503 | 310,568 | ||||||
| Revisions to estimated cash flows | 146,682 | 166,947 | ||||||
| Ending balance | $ | 6,069,993 | $ | 5,682,556 | ||||
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 theCustomer Receivables and Allowance for Doubtful Accounts
Due to the impact of COVID-19 on businesses and individuals, including the moratorium on customer disconnections for non payment, customer delinquent and past due balances increased significantly in fiscal 2021. The allowance for credit losses disclosed below was adjusted to reflect the impact of $859,000 in ARPA funds received in fiscal 2022. Without the ARPA and CARES Act funds, the allowance for credit losses would have been more than $1 million as of September 30, 2021.
A reconciliation of changes in the allowance for doubtful accountscredit losses is as follows:
Years Ended September 30 | ||||||||
2022 | 2021 | |||||||
Beginning balance | $ | 242,010 | $ | 703,140 | ||||
Provision for credit losses | 492,875 | (400,614 | ) | |||||
Recoveries of accounts written off | 135,143 | 88,893 | ||||||
Accounts written off | (498,757 | ) | (149,409 | ) | ||||
Ending balance | $ | 371,271 | $ | 242,010 | ||||
| Years Ended September 30 | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
| Beginning balance | $ | 76,934 | $ | 52,721 | $ | 70,747 | ||||||
| Provision for doubtful accounts | 84,587 | 14,074 | 87,908 | |||||||||
| Recoveries of accounts written off | 110,725 | 137,055 | 139,282 | |||||||||
| Accounts written off | (172,790 | ) | (126,916 | ) | (245,216 | ) | ||||||
| Ending balance | $ | 99,456 | $ | 76,934 | $ | 52,721 | ||||||
Lease Accounting—The Company leases certain assets including office space, land, and equipment classified as operating leases. As the terms of these leases are for a short duration and their value was determined to be de minimis, a right-of-use asset and corresponding lease liability for leases with original lease terms of one year or more are not included in the consolidated balance sheet.
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,Inventories
—Unbilled Revenues
—The Company bills its natural gas customers on a monthly cycle; however, the billing cycleIncome 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 consolidated 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’sFair Value
—Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between willing market participants at the measurement date. The Company determines fair value based on the following fair value hierarchy which prioritizes each input to the valuation methods into one of the following three broad levels:• | Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date. |
• | Level 2 – Inputs other than quoted prices in Level 1 that are either for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, or inputs that are derived principally from or corroborated by observable market data by correlation or other means. |
• | Level 3 – Unobservable inputs for the asset or liability where there is little, if any, market activity which require the Company to develop its own assumptions. |
The fair value hierarchy gives the highest priority to unadjusted quoted prices in active markets (Level 1)1) and the lowest priority to unobservable inputs (Level 3)3). All fair value disclosures are categorized within one of the three categories in the hierarchy. See fair value disclosures below and in Notes 89 and 12.
Use of Estimates
—The preparation of consolidated financial statements in conformity withExcise 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’sEarnings Per Share—Basic earnings per shareEPS and diluted earnings per shareEPS 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 earnings per shareEPS is presented below:
Years Ended September 30 | ||||||||
2022 | 2021 | |||||||
Net Income (Loss) | $ | (31,732,602 | ) | $ | 10,102,062 | |||
Weighted-average common shares | 9,122,678 | 8,251,802 | ||||||
Effect of dilutive securities: | ||||||||
Options to purchase common stock | — | 13,102 | ||||||
Diluted average common shares | 9,122,678 | 8,264,904 | ||||||
Earnings Per Share of Common Stock: | ||||||||
Basic | $ | (3.48 | ) | $ | 1.22 | |||
Diluted | $ | (3.48 | ) | $ | 1.22 | |||
| Years Ended September 30 | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
| Net Income | $ | 6,232,865 | $ | 5,806,866 | $ | 5,094,415 | ||||||
| Weighted-average common shares | 7,218,686 | 7,149,906 | 7,092,315 | |||||||||
| Effect of dilutive securities: | ||||||||||||
| Options to purchase common stock | 37,360 | 9,857 | 5,199 | |||||||||
| Diluted average common shares | 7,256,046 | 7,159,763 | 7,097,514 | |||||||||
| Earnings Per Share of Common Stock: | ||||||||||||
| Basic | $ | 0.86 | $ | 0.81 | $ | 0.72 | ||||||
| Diluted | $ | 0.86 | $ | 0.81 | $ | 0.72 | ||||||
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 orperiod. One customer amounted to approximately 5.1% of total accounts receivable at September 30, 2022 and no individual customer amounted to more than 5% of total accounts receivable.
Roanoke Gas currently holds the only franchises and certificates of public convenience and necessityCPCNs to distribute natural gas in its service area. These franchises are effective through January 1, 2036. expire December 31, 2035. The Company's current certificates of public convenience and necessityCPCNs 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
—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 RGC Resources, Inc. hedgesthe 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 sheetsheets with the offsetting entry to either under-recovery of gas costsunder- 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, 20172022 and 2016,2021, the Company had no outstanding derivative instruments for the purchase of natural gas.
The Company had onehas five interest rate swapswaps associated with its $7,000,000variable rate debt. During fiscal 2021, Roanoke Gas entered into two delayed draw variable-rate term notenotes in the amounts of $15 million and $10 million, with Branch Banking & Trust as discussedcorresponding swap agreements to convert the variable interest rates into fixed rates of 2.00% and 2.49%, respectively. Midstream has two variable-rate term notes in Note 6. Effective 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. In addition, on November 1, 2017,2021, Midstream entered into a promissory note in the amount of $8 million, with a corresponding swap agreement convertsto convert the floatingvariable interest rate note based on LIBOR into a fixed rate debt with a 2.30% effective interest rate. The swap qualifiesof 2.443%. 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 swap wasswaps were deemed ineffective during the period.
See Notes 7 and its corresponding classification in the consolidated balance sheets.
| September 30 | |||||||
| 2017 | 2016 | ||||||
| Derivatives designated as hedging instruments: | |||||||
| Current assets: | |||||||
| Interest rate swap | $ | 26,777 | $ | — | |||
| Other assets: | |||||||
| Interest rate swap | $ | 90,066 | $ | — | |||
| Total derivatives designated as hedging instruments | $ | 116,843 | $ | — | |||
Non-Cash Activity —A non-cash increase in investmentdecrease in unconsolidated affiliate and corresponding increasedecrease in capital contributions payable of $767,710$1,336,131 and $287,794$371,800 occurred for the fiscal years ended September 30, 20172022 and 2016,2021, respectively.
Other Comprehensive Income (Loss)
—A summary of other comprehensive income is provided below:Before Tax Amount | Tax (Expense) or Benefit | Net of Tax Amount | ||||||||||
| Year Ended September 30, 2017: | ||||||||||||
| Interest rate swap: | ||||||||||||
| Unrealized gains | $ | 116,843 | $ | (44,354 | ) | $ | 72,489 | |||||
| Net interest rate swap | 116,843 | (44,354 | ) | 72,489 | ||||||||
| Defined benefit plans: | ||||||||||||
| Net gain arising during period | $ | 1,715,505 | $ | (651,892 | ) | $ | 1,063,613 | |||||
| Amortization of actuarial losses | 256,234 | (97,369 | ) | 158,865 | ||||||||
| Net defined benefit plans | 1,971,739 | (749,261 | ) | 1,222,478 | ||||||||
| Other comprehensive income | $ | 2,088,582 | $ | (793,615 | ) | $ | 1,294,967 | |||||
| Year Ended September 30, 2016: | ||||||||||||
| Defined benefit plans: | ||||||||||||
| Net loss arising during period | $ | (560,887 | ) | $ | 213,137 | $ | (347,750 | ) | ||||
| Amortization of actuarial losses | 221,070 | (84,006 | ) | 137,064 | ||||||||
| Net defined benefit plans | (339,817 | ) | 129,131 | (210,686 | ) | |||||||
| Other comprehensive loss | $ | (339,817 | ) | $ | 129,131 | $ | (210,686 | ) | ||||
| Year Ended September 30, 2015: | ||||||||||||
| Defined benefit plans: | ||||||||||||
| Net loss arising during period | (1,910,573 | ) | 726,017 | (1,184,556 | ) | |||||||
| Amortization of actuarial losses | 60,221 | (22,884 | ) | 37,337 | ||||||||
| Net defined benefit plans | (1,850,352 | ) | 703,133 | (1,147,219 | ) | |||||||
| Other comprehensive loss | $ | (1,850,352 | ) | $ | 703,133 | $ | (1,147,219 | ) | ||||
Tax | ||||||||||||
Before Tax | (Expense) | Net of Tax | ||||||||||
Amount | or Benefit | Amount | ||||||||||
Year Ended September 30, 2022: | ||||||||||||
Interest rate swaps: | ||||||||||||
Unrealized gains | $ | 5,617,251 | $ | (1,445,878 | ) | $ | 4,171,373 | |||||
Transfer of realized losses to interest expense | 377,299 | (97,121 | ) | 280,178 | ||||||||
Net interest rate swaps | 5,994,550 | (1,542,999 | ) | 4,451,551 | ||||||||
Defined benefit plans: | ||||||||||||
Net losses arising during period | $ | (1,221,368 | ) | $ | 314,379 | $ | (906,989 | ) | ||||
Amortization of actuarial gains | (60,280 | ) | 15,516 | (44,764 | ) | |||||||
Net defined benefit plans | (1,281,648 | ) | 329,895 | (951,753 | ) | |||||||
Other comprehensive income | $ | 4,712,902 | $ | (1,213,104 | ) | $ | 3,499,798 | |||||
Year Ended September 30, 2021: | ||||||||||||
Interest rate swaps: | ||||||||||||
Unrealized gains | $ | 473,880 | $ | (121,978 | ) | $ | 351,902 | |||||
Transfer of realized losses to interest expense | 553,593 | (142,492 | ) | 411,101 | ||||||||
Net interest rate swaps | 1,027,473 | (264,470 | ) | 763,003 | ||||||||
Defined benefit plans: | ||||||||||||
Net gains arising during period | $ | 1,467,879 | $ | (377,832 | ) | $ | 1,090,047 | |||||
Amortization of actuarial losses | 80,069 | (20,609 | ) | 59,460 | ||||||||
Net defined benefit plans | 1,547,948 | (398,441 | ) | 1,149,507 | ||||||||
Other comprehensive income | $ | 2,575,421 | $ | (662,911 | ) | $ | 1,912,510 | |||||
The amortization of actuarial gains or losses isare included as a component of net periodic pension and postretirement benefit costs under other income, net in operations and maintenance expense.
Composition of Accumulated Other Comprehensive Income (Loss):
Interest Rate Swaps | Defined Benefit Plans | Accumulated Other Comprehensive Income (Loss) | ||||||||||
Balance September 30, 2020 | $ | (1,651,213 | ) | $ | (1,796,731 | ) | $ | (3,447,944 | ) | |||
Other comprehensive income | 763,003 | 1,149,507 | 1,912,510 | |||||||||
Balance September 30, 2021 | (888,210 | ) | (647,224 | ) | (1,535,434 | ) | ||||||
Other comprehensive income (loss) | 4,451,551 | (951,753 | ) | 3,499,798 | ||||||||
Balance September 30, 2022 | $ | 3,563,341 | $ | (1,598,977 | ) | $ | 1,964,364 | |||||
Interest Rate Swaps | Defined Benefit Plans | Accumulated Other Comprehensive Income (Loss) | ||||||||||
| Balance September 30, 2014 | $ | — | $ | (1,139,326 | ) | $ | (1,139,326 | ) | ||||
| Other comprehensive income (loss) | — | (1,147,219 | ) | (1,147,219 | ) | |||||||
| Balance September 30, 2015 | — | (2,286,545 | ) | (2,286,545 | ) | |||||||
| Other comprehensive income (loss) | — | (210,686 | ) | (210,686 | ) | |||||||
| Balance September 30, 2016 | — | (2,497,231 | ) | (2,497,231 | ) | |||||||
| Other comprehensive income (loss) | 72,489 | 1,222,478 | 1,294,967 | |||||||||
| Balance September 30, 2017 | $ | 72,489 | $ | (1,274,753 | ) | $ | (1,202,264 | ) | ||||
Recently Adopted Accounting Standards
In November 2015, January 2018, the FASB issued ASU 2015-17,
In August 2017, 2018, the FASB issued ASU 2017-12, Derivatives2018-14,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 Hedging: Targeted Improvementsrecognizing the effects of reference rate change on financial reporting. The new guidance applies specifically to Accounting For Hedging Activities. The ASU is meant to simplify recognitioncontracts and presentation guidance in an effort to improve financial reporting of cash flow and fair value hedging relationships that reference LIBOR, or any other referenced rate that is expected to better portray the economic results of an entity's risk management activities. This is achieved through changesbe discontinued due to both the designation and measurement guidance for qualifying hedging relationships, as well as changes to the presentation of hedge results.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 annual reporting period ending September 30, 2020LIBOR rates for one-day, one-month, six-month and interim periods withinone-year will cease publication in June 2023 and that annual period. Early adoption is permitted. Management has not completed its evaluationno new financial contracts may use LIBOR after December 31, 2021. Currently, all of the new guidance; however, itCompany'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 currently expect the anticipate adopting this guidance until fiscal 2023. The new guidance to havecould result in a material effectsignificant impact on itsthe Company's financial position, results of operations, orand cash flows.
Other accounting standards that have been issued or proposed by the FASB or other standard–setting bodies are not currently applicable to the Company or are not expected to have a significant impact on the Company’s financial position, results of operations and cash flows.
Reclassification
Certain prior year amounts of share and per share data have been restated retrospectivelyreclassified to reflectconform to current year presentations.
2. | REVENUE |
The Company assesses new contracts and identifies related performance obligations for promises to transfer distinct goods or services to the 50% stock dividend.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:
2022 | ||||||||||||
Gas utility | Non utility | Total operating revenues | ||||||||||
Natural Gas (Billed and Unbilled): | ||||||||||||
Residential | $ | 46,915,892 | $ | — | $ | 46,915,892 | ||||||
Commercial | 28,874,522 | — | 28,874,522 | |||||||||
Industrial and Transportation | 5,671,884 | — | 5,671,884 | |||||||||
Other | 822,140 | 129,578 | 951,718 | |||||||||
Total contracts with customers | 82,284,438 | 129,578 | 82,414,016 | |||||||||
Alternative Revenue Programs | 1,751,206 | — | 1,751,206 | |||||||||
Total operating revenues | $ | 84,035,644 | $ | 129,578 | $ | 84,165,222 | ||||||
2021 | ||||||||||||
Gas utility | Non utility | Total operating revenues | ||||||||||
Natural Gas (Billed and Unbilled): | ||||||||||||
Residential | $ | 43,108,790 | $ | — | $ | 43,108,790 | ||||||
Commercial | 25,217,030 | — | 25,217,030 | |||||||||
Industrial and Transportation | 4,973,885 | — | 4,973,885 | |||||||||
Other | 429,397 | 129,676 | 559,073 | |||||||||
Total contracts with customers | 73,729,102 | 129,676 | 73,858,778 | |||||||||
Alternative Revenue Programs | 1,316,001 | — | 1,316,001 | |||||||||
Total operating revenues | $ | 75,045,103 | $ | 129,676 | $ | 75,174,779 | ||||||
Gas utility revenues
Substantially all of Roanoke Gas’ revenues are derived from rates authorized by the SCC through its tariffs. Based on its evaluation, the Company has concluded that these tariff-based revenues fall within the scope of ASC 606. Tariff rates represent the transaction price. Performance obligations created under these tariff-based sales include commodity (the cost of natural gas sold to customers) and delivery (transporting natural gas through the Company’s distribution system to customers). The delivery of natural gas to customers results in the satisfaction of the Company’s respective performance obligations over time.
All customers are billed monthly based on consumption as measured by metered usage with payments due 20 days from the rendering of the bill. Revenue is recognized as bills are issued for natural gas that has been delivered or transported. In addition, the Company utilizes the practical expedient that allows an entity to recognize the invoiced amount as revenue, if that amount corresponds to the value received by the customer. Since customers are billed tariff rates, there is no variable consideration in the transaction price.
Unbilled revenue is included in residential and commercial revenues in the preceding table. Natural gas consumption is estimated for the period subsequent to the last billed date and up through the last day of the month. Estimated volumes and approved tariff rates are utilized to calculate unbilled revenue. The following month, the unbilled estimate is reversed, the actual usage is billed and a new unbilled estimate is calculated. The Company obtains metered usage for industrial customers at the end of each month, thereby eliminating any unbilled consideration for these rate classes.
Other revenues
Other revenues primarily consist of miscellaneous fees and charges, utility-related revenues not directly billed to utility customers and billings for non-utility activities. Regarding these activities, the customer is invoiced monthly based on services provided. The Company utilizes the practical expedient allowing revenue to be recognized based on invoiced amounts. The transaction price is based on a contractually predetermined rate schedule; therefore, the transaction price represents total value to the customer and no variable price consideration exists.
Alternative Revenue Program revenues
ARPs, which fall outside the scope of ASC 606, are SCC approved mechanisms that allow for the adjustment of revenues for certain broad, external factors, or for additional billings if the entity achieves certain performance targets. The Company's ARPs include its WNA, which adjusts revenues for the effects of weather temperature variations as compared to the 30-year average, and the SAVE Plan over/under collection mechanism, which adjusts revenues for the differences between SAVE Plan revenues billed to customers and the revenues earned, as calculated based on the timing and extent of infrastructure replacement completed during the period. These amounts are ultimately collected from, or returned to, customers through future rate changes approved by the SCC.
Customer Accounts Receivable
Accounts receivable, as reflected in the condensed consolidated balance sheets, includes both billed and unbilled customer revenues, as well as amounts that are not related to customers. The balances of customer receivables are provided below:
Current Assets | Current Liabilities | |||||||||||||||
Trade accounts receivable (1) | Unbilled revenue (1) | Customer credit balances | Customer deposits | |||||||||||||
September 30, 2021 | $ | 3,722,916 | $ | 1,191,227 | $ | 1,539,680 | $ | 1,571,342 | ||||||||
September 30, 2022 | 3,697,431 | 1,585,062 | 1,400,770 | 1,457,610 | ||||||||||||
Increase (decrease) | $ | (25,485 | ) | $ | 393,835 | $ | (138,910 | ) | $ | (113,732 | ) | |||||
(1)Included in "Accounts receivable, net" in the consolidated balance sheet. Amounts shown net of reserve for bad debts. |
The Company had no significant contract assets or liabilities during the period. Furthermore, the Company did not incur any significant costs to obtain contracts.
3. | |
REGULATORY MATTERS |
The SCC exercises regulatory authority over the natural gas operations of Roanoke Gas. Such regulation encompasses terms, conditions and rates to be charged to customers for natural gas service, safety standards, service extension accounting and depreciation.
In April 2020, the Company filedSCC issued an order allowing regulated utilities in Virginia to defer certain incremental, prudently incurred costs associated with the SCCCOVID-19 pandemic and to apply for recovery at a future date. For the years ended September 30, 2022 and 2021, Roanoke Gas deferred certain COVID-19 related costs during the respective years. However, based on the Company’s preliminary earnings test for each year, the Company’s earnings exceeded the authorized return on equity on which the Company’s rates were established in its last rate proceeding. Accordingly, Roanoke Gas expensed the deferred COVID-19 related costs during the corresponding fourth quarters.
Roanoke Gas continues to recover the costs of its infrastructure replacement program through its SAVE Rider. In May 2022, Roanoke Gas filed its most recent SAVE (Stepsapplication with the SCC to Advance Virginia's Energy) Plan and Rider. The SAVE Plan provides a mechanism for the Company to recover the related depreciation and expenses and return on rate base of the additional capital investment without the filing of a formal application for an increase in non-gas base rates. Under the current application, the Company submitted its report for collecting the shortfall in SAVE revenues collected under the 2016 SAVE Plan and proposed new 2018 SAVE rates to be implemented for the ongoing investment in SAVE Plan projects. On September 28, 2017, the Company received approval of its application to implement the new 2018 SAVE rates related to proposed qualifying SAVE investments in calendar 2018. The SCC also approved the True-Up factor to provide collection on the remaining under-collected 2016 SAVE Plan for a modification toupdate the SAVE Plan and Rider for the period October 2022 through September 2023. The updated SAVE Rider is designed to collect approximately $4.1 million in annual revenues representing approximately a $650,000 increase over the current SAVE Rider.
On May 16, 2022, Roanoke Gas announced a cooperative agreement under which Roanoke Gas and the Western Virginia Water Authority will produce commercial quality RNG from biogas produced at the regional water pollution control plant. In October 2015,August 2022, Roanoke Gas filed an application with the SCC seeking approval of a rate adjustment clause under which the Company will recover the costs associated with constructing, owning, operating and maintaining the renewable natural gas facility. The application was filed under Chapter 30 of Title 56 of the Code of Virginia. The Company expects a final order from the Commission in January 2023.
On June 2, 2022, Roanoke Gas filed an application with the SCC to acquire certain natural gas delivery assets from a local housing authority. Under this application, the Company requested the approval to acquire such facilities at five separate apartment complexes, located in the Company’s service territory, that were under housing authority management. Under the proposed plan, the housing authority would renew existing natural gas distribution facilities to include mains, services, and meter installations and then transfer ownership of these facilities to Roanoke Gas. In turn, Roanoke Gas would assume responsibility for the operation and maintenance of these assets and recognize a gain related to the asset acquisition equal to the cost associated with the renewal.
On July 19, 2022, the SCC approved the application and on August 4, 2022, the housing authority transferred the assets from two apartment complexes to Roanoke Gas. Roanoke Gas recorded these assets and recognized a pre-tax gain of approximately $219,000 during the Company’s fiscal fourth quarter. The housing authority expects to complete the upgrade and subsequent asset transfer at one more apartment complex in fiscal 2023. The authority is awaiting future funding to complete two additional apartment complexes. The timing of funding and the completion of the asset renewals for these two complexes is unknown at this time.
On September 30, 2022, the Company filed notice with the SCC that it intended to file a non-gas base rate case. The Company plans to file in early December with the rates expected to become effective on January 1, 2023 on an interim basis subject to refund.
In the final order from the last non-gas base rate increase, the SCC allowed Roanoke Gas to defer the related financing costs of two gate stations that would interconnect to MVP 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. Beginning January 2021, Roanoke Gas temporarily ceased recording AFUDC on its related MVP interconnect construction projects until such time as construction activities resume. For the year ended September 30, 2021, the Company recognized a total of $55,981 in AFUDC. In connection with the RNG project, Roanoke Gas began accruing AFUDC in fiscal 2022 associated with construction of the facility. For the year ended September 30, 2022, Roanoke Gas recognized a total of $75,154 in AFUDC associated with the RNG project.
4. | SEGMENT INFORMATION |
Operating segments are defined as components of an enterprise for which separate financial information is available and is evaluated regularly by the Company's executive management in deciding how to allocate resources and assess performance. The Company uses operating income and equity in earnings to assess segment performance.
Intersegment transactions are recorded at cost.
The reportable segments disclosed herein are defined as follows:
Gas Utility - The natural gas distribution segment of the Company generates revenue from its tariff rates and other regulatory mechanisms through which it provides for the sale and distribution of natural gas to its wholly-owned subsidiary, RGC residential, commercial and industrial customers.
Investment in Affiliates - The investment in affiliates segment reflects the income generated through the activities of the Company's investment in MVP and Southgate projects.
Parent and Other - Parent and other include the unregulated activities of the Company as well as certain corporate eliminations.
Information related to the segments of the Company are provided below:
Gas Utility | Investment in Affiliates | Parent and Other | Consolidated Total | |||||||||||||
For the Year Ended September 30, 2022: | ||||||||||||||||
Operating revenues | $ | 84,035,644 | $ | — | $ | 129,578 | $ | 84,165,222 | ||||||||
Depreciation | 8,948,923 | — | — | 8,948,923 | ||||||||||||
Operating income (loss) | 15,104,946 | (281,843 | ) | 93,572 | 14,916,675 | |||||||||||
Equity in earnings | — | 73,327 | — | 73,327 | ||||||||||||
Impairment of investments in affiliates | — | (55,092,303 | ) | — | (55,092,303 | ) | ||||||||||
Interest expense | 3,001,926 | 1,496,003 | — | 4,497,929 | ||||||||||||
Income (loss) before income taxes | 13,547,601 | (56,784,957 | ) | 94,109 | (43,143,247 | ) | ||||||||||
As of September 30, 2022: | ||||||||||||||||
Total assets | $ | 258,519,230 | $ | 13,838,108 | $ | 17,951,905 | $ | 290,309,243 | ||||||||
Gross additions to utility property | 25,461,000 | — | — | 25,461,000 | ||||||||||||
Gross investment in affiliates | — | 5,260,863 | — | 5,260,863 | ||||||||||||
Gas Utility | Investment in Affiliates | Parent and Other | Consolidated Total | |||||||||||||
For the Year Ended September 30, 2021: | ||||||||||||||||
Operating revenues | $ | 75,045,103 | $ | — | $ | 129,676 | $ | 75,174,779 | ||||||||
Depreciation | 8,424,620 | — | — | 8,424,620 | ||||||||||||
Operating income (loss) | 14,955,375 | (267,391 | ) | 90,325 | 14,778,309 | |||||||||||
Equity in earnings | — | 1,667,554 | — | 1,667,554 | ||||||||||||
Interest expense | 2,812,107 | 1,239,778 | — | 4,051,885 | ||||||||||||
Income before income taxes | 13,043,470 | 171,861 | 90,793 | 13,306,124 | ||||||||||||
As of September 30, 2021: | ||||||||||||||||
Total assets | $ | 231,737,427 | $ | 65,686,376 | $ | 12,685,390 | $ | 310,109,193 | ||||||||
Gross additions to utility property | 19,967,567 | — | — | 19,967,567 | ||||||||||||
Gross investment in affiliates | — | 6,028,760 | — | 6,028,760 | ||||||||||||
5. | OTHER INVESTMENTS |
Midstream LLC ("Midstream"), acquired ais an approximately 1% equity interest ininvestment owner of the Mountain Valley Pipeline, LLC (the “LLC”).
The LLC temporarily suspended accruing AFUDC on the project beginning January 1, 2021 and through south central Virginia.March 31, 2021 due to a temporary reduction in growth construction activities. The proposed pipelineLLC resumed accruing AFUDC beginning April 2021 through November 2021 when certain associated growth construction activities were again reduced. AFUDC accruals will haveresume when growth construction activities restart. The amount of AFUDC recognized during the capacitycurrent and prior years is included in the tables below.
Roanoke Gas will continue to transport approximately 2 million decathermssuspend accruing AFUDC on its two gate stations that will interconnect with the MVP until such time as construction activities resume on the respective gate stations.
Midstream is a less than 1% investor in Southgate, which is being accounted for under the cost method.
On January 25, 2022, the Fourth Circuit vacated and remanded on specific issues certain permits issued by the Bureau of natural gas per day. On October 13, 2017,Land Management and the Federal Energy Regulatory Commission issued the Certificate of Public Convenience and Necessity subjectU.S. Forest Service to certain conditions and requirements. With FERC approval, the LLC will continuein respect of the processJefferson National Forest. On February 3, 2022, the Fourth Circuit vacated and remanded on specific issues the Biological Opinion and Incidental Take Statement issued by the U.S. Fish and Wildlife Service for MVP. Primarily due to these unfavorable decisions by the Fourth Circuit, Midstream identified as an indicator of obtainingan other-than-temporary decline in value the necessaryincreased uncertainty of the completion and commercial operation of MVP and Southgate. As a result, Midstream assessed the value of its investment in the LLC as of February 22, 2022 to determine if its investment's carrying value exceeded the fair value.
Midstream estimated the fair value of its investment in the LLC, with the assistance of a valuation specialist, using an income-based approach that primarily considered probability-weighted scenarios of discounted future cash flows based on the estimated project costs at completion and projected revenues. These scenarios reflected assumptions and judgments regarding the ultimate outcome of further matters relating to, or resulting from, the January and February 2022 Fourth Circuit rulings, as well as various other ongoing legal and regulatory matters affecting MVP and Southgate. Such assumptions and judgments also included certain additional potential delays and related cost increases that could result from unfavorable decisions on these proceedings and matters. Midstream’s analysis also took into account, among other things, probability weighted growth expectations from additional compression expansion opportunities. This analysis also considered scenarios under which ongoing or new legal and regulatory matters further delay the completion and increase the total costs of the project; all required legal and regulatory approvals and permits from other federalauthorizations and state government agencies. Assuming no significant delayscertain compression expansion opportunities are realized; and MVP and Southgate are canceled. As a result of the assessment, Midstream recognized a pre-tax impairment loss of approximately $39.8 million in the second quarter of fiscal 2022.
Midstream reassesses the value of its investment in the LLC on at least a quarterly basis. With the assistance of a valuation specialist, Midstream conducted the quarterly evaluation of its investment in the LLC as of September 30, 2022. During the fourth quarter of 2022, Midstream recognized an additional pre-tax impairment charge of $15.3 million in its equity investment in the LLC primarily due to increased uncertainty in the permitting process for the pipeline is expectedMVP project as a result of recent legal developments and regulatory uncertainties, as well as macroeconomic pressures primarily due to be in service by late 2018.
There is risk that Midstream’s equity investment in the LLC may be impaired further in the future. There are continuing, and potential future, legal and regulatory matters related to MVP, any of which could affect the ability to complete or operate the project, as well as potential macroeconomic factors, changes in interest rates, cost increases, other unanticipated events and legal and regulatory matters related to Southgate that must be resolved. While macroeconomic factors in and of themselves may not be a direct indicator of impairment, should an impairment indicator be identified in the future, macroeconomic factors such as changes in interest rates could ultimately impact the size and scope of any potential impairment. Assumptions and estimates utilized in assessing the fair value of Midstream’s investment in the LLC may change depending on the nature or timing of resolutions to the legal and regulatory matters or based on other relevant developments. Adverse changes in circumstances relevant to the likelihood of project or expansion completion could prompt Midstream, in future assessments, to apply lower probability of project or expansion completion and such changes in assumptions or estimates, including discount rates, could have a material adverse effect on the fair value of Midstream’s investment in the LLC and potentially result in an additional impairment, which could have a material adverse effect on the results of operations and financial position of Midstream and the Company as a whole.
Funding for Midstream's investments in the LLC for both MVP and Southgate is being provided through two variable rate unsecured Promissory Notes, each withpromissory notes, under a 5-year term,non-revolving credit agreement maturing in December 2023, and three additional notes as further describeddetailed in Note 6 below.
The Company will participate in the earnings generated from the transportation of natural gas through the pipeline in proportionboth pipelines proportionate to its level of investment.
The financial statement locations of the investmentinvestments in the LLC are included in the consolidated financial statements as follows:
September 30 | ||||||||
Balance Sheet location: | 2022 | 2021 | ||||||
Other Assets: | ||||||||
MVP | $ | 13,689,370 | $ | 64,462,194 | ||||
Southgate | 83,705 | 405,125 | ||||||
Investment in unconsolidated affiliates | $ | 13,773,075 | $ | 64,867,319 | ||||
Current Liabilities: | ||||||||
MVP | $ | 804,404 | $ | 2,139,696 | ||||
Southgate | 102 | 941 | ||||||
Capital contributions payable | $ | 804,506 | $ | 2,140,637 | ||||
Years Ended September 30 | ||||||||
Income Statement location: | 2022 | 2021 | ||||||
Equity in earnings of unconsolidated affiliate | $ | 73,327 | $ | 1,667,554 | ||||
September 30 | ||||||||
2022 | 2021 | |||||||
Undistributed earnings, net of income taxes, of MVP in retained earnings, excluding impairment | $ | 8,135,482 | $ | 8,081,027 | ||||
The change in the investment in unconsolidated affiliates is provided below:
September 30 | ||||||||
2022 | 2021 | |||||||
Cash investment | $ | 5,260,863 | $ | 6,028,760 | ||||
Change in accrued capital calls | (1,336,131 | ) | (371,800 | ) | ||||
Pre-tax impairment | (55,092,303 | ) | — | |||||
Equity in earnings of unconsolidated affiliate | 73,327 | 1,667,554 | ||||||
Change in investment in unconsolidated affiliates | $ | (51,094,244 | ) | $ | 7,324,514 | |||
| September 30 | ||||||||||||
| Balance Sheet Location of Other Investments: | 2017 | 2016 | ||||||||||
| Other Assets: | ||||||||||||
| Investment in unconsolidated affiliate | $ | 7,445,106 | $ | 3,496,404 | ||||||||
| Current Liabilities: | ||||||||||||
| Capital contributions payable | $ | 1,055,504 | $ | 287,794 | ||||||||
| For the Years ended September 30 | ||||||||||||
| Income Statement Location of Other Investments: | 2017 | 2016 | 2015 | |||||||||
| Equity in earnings of unconsolidated affiliate | $ | 421,646 | $ | 152,864 | $ | — | ||||||
Summary unaudited financial statements of MVP are presented below. Southgate financial statements, which are accounted for under the cost method, are not included:
Income Statements | ||||||||
Years Ended September 30 | ||||||||
2022 | 2021 | |||||||
AFUDC | $ | 6,883,069 | $ | 165,048,237 | ||||
Net other income (expense) | 147,154 | (388,436 | ) | |||||
Net income | $ | 7,030,223 | $ | 164,659,801 | ||||
Balance Sheets | ||||||||
September 30 | ||||||||
2022 | 2021 | |||||||
Assets: | ||||||||
Current assets | $ | 76,474,981 | $ | 208,961,113 | ||||
Construction work in progress | 6,667,146,408 | 6,281,991,035 | ||||||
Other assets | 8,021,877 | 980,410 | ||||||
Total assets | $ | 6,751,643,266 | $ | 6,491,932,558 | ||||
Liabilities and Equity: | ||||||||
Current liabilities | $ | 115,061,723 | $ | 200,441,027 | ||||
Noncurrent liabilities | — | 13,000 | ||||||
Capital | 6,636,581,543 | 6,291,478,531 | ||||||
Total liabilities and equity | $ | 6,751,643,266 | $ | 6,491,932,558 | ||||
6. | LINE-OF-CREDIT |
On March 27, 2017, 31, 2022, Roanoke Gas entered into a newan unsecured line-of-credit agreement. Thisagreement replacing the line-of-credit agreement replaced thedated March 25, 2021. The agreement which expired on March 31, 2017. The expired agreement wasprovides for a term of one year and all amounts drawn against that agreement were considered to be current liabilities. The new line-of-credit agreement is for a two-year term expiring March 31, 2019. Amounts drawn against the new 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.
In connection with the line-of-credit, the Company also entered into the Seventh Amendment to Credit Agreement as of March 31, 2022, which amends the original Credit Agreement dated March 31, 2016 and minimizeall subsequent amendments. The Amendment aligns the termination date and maximum principle amount available under the line-of-credit, amends certain financial conditions required of Resources, and retains all other terms and requirements of prior credit agreements.
The Company's total available borrowing costs. Available limits under this agreement for the remaining term are as follows:
Available | |||||
As of | Line-of-Credit | ||||
September 30, 2022 | $ | 28,000,000 | |||
October 19, 2022 | 33,000,000 | ||||
March 1, 2023 | 30,000,000 | ||||
| As of | Available Line-of-Credit | |||
| September 30, 2017 | $ | 21,000,000 | ||
| March 1, 2018 | 17,000,000 | |||
| July 22, 2018 | 22,000,000 | |||
| September 22, 2018 | 30,000,000 | |||
A summary of the line-of-credit follows:
| September 30 | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
| Line-of-credit at year-end | $ | 21,000,000 | $ | 24,000,000 | $ | 24,000,000 | ||||||
| Outstanding balance at year-end | 17,791,760 | 14,556,785 | 9,340,997 | |||||||||
| Highest month-end balance outstanding | 17,791,760 | 15,246,089 | 17,366,052 | |||||||||
| Average daily balance | 10,936,114 | 9,620,914 | 6,377,040 | |||||||||
| Average rate of interest during year on outstanding balances | 1.92 | % | 1.40 | % | 1.17 | % | ||||||
| Interest rate at year-end | 2.23 | % | 1.53 | % | 1.20 | % | ||||||
| Interest rate on unused line-of-credit | 0.15 | % | 0.15 | % | 0.15 | % | ||||||
September 30 | ||||||||
2022 | 2021 | |||||||
Available line-of-credit at year-end | $ | 28,000,000 | $ | 32,000,000 | ||||
Outstanding balance at year-end | — | 17,628,897 | ||||||
Highest month-end balance outstanding | 19,636,179 | 17,628,897 | ||||||
Average daily balance | 6,233,620 | 10,042,073 | ||||||
Average rate of interest during year on outstanding balances | 1.15 | % | 1.12 | % | ||||
Interest rate at year-end | 4.08 | % | 1.08 | % | ||||
Interest rate on unused line-of-credit | 0.15 | % | 0.15 | % | ||||
Associated with the line-of-credit is a credit agreement that contains various representations, warranties and covenants including a requirement that the Company maintain an interest coverage ratio of not less than 1.5 to 1 and a long-term debt to long-term capitalization ratio of less than 65%.
7. | |
LONG-TERM DEBT |
On November 1,2021 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 January 1, 2016, 2028. 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 reduced 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. On March 31, 2022, Midstream applied $10 million from a cash infusion received from Resources to pay down a corresponding amount on the non-revolving credit facility which in turn reduced the total borrowing capacity from $33 million to $23 million. On June 30, 2022 Midstream entered into the Fourth Amendment to Credit Agreement and related Promissory Notes. The Amendment modifies the original Credit Agreement and prior amendments by replacing the 30-day LIBOR plus 1.35% interest on the Promissory Notes with Term SOFR plus 1.50% as well as extended the maturity date to December 31, 2023. All other terms of the Fourth Amendment to Credit Agreement remain unchanged.
On September 24, 2021, Roanoke Gas entered into a 5-yearLoan Agreement ("Agreement") and an unsecured note with Branch Banking & TrustDelayed Draw Promissory Note in the principal amount of $7,000,000. $10 million ("Promissory Note"). Under the provisions of the Agreement, Roanoke Gas received the first advance of $5 million on April 1, 2022 and the remaining $5 million on September 30, 2022. The note isPromissory Note has an interest rate of 30-day LIBOR plus 100 basis points and a maturity date of October 1, 2028. The proceeds from this Promissory Note were used to finance Roanoke Gas' infrastructure enhancement and replacement projects. Also, on September 24, 2021, Roanoke Gas entered into an interest rate swap agreement for $10 million corresponding to the term and draw provisions of the Agreement, which effectively converted the variable rate Promissory Note to a fixed instrument with an effective annual interest basedrate of 2.49%.
On August 20, 2021, Roanoke Gas entered into an unsecured Delayed Draw Term Note in the principal amount of $15 million ("Term Note") with an interest rate of 1.20% above 30-day SOFR Average per annum maturing on 30-day LIBOR plus 90 basis points. August 20, 2026. In addition,connection with the Term Note, Roanoke Gas also entered into the Sixth Amendment to its Credit Agreement ("Amendment"), which amends the original Credit Agreement with the corresponding bank dated March 31, 2016 and all subsequent amendments. The Amendment aligns the termination date and the maximum principal amount available under the Term Note and retains all other terms and requirements of prior credit agreements. The proceeds from this Term Note were used to finance Roanoke Gas' infrastructure enhancement and replacement projects, as well as to refinance a portion of its existing debt. Also, on August 20, 2021, Roanoke Gas entered into an interest rate swap agreement with Branch Banking & Trustfor $15 million corresponding to convertthe duration of the Term Note, which effectively converted the variable rate debt intonote to a fixed-ratefixed rate instrument with an effective annual interest rate of 2.30%2.00%. The swap agreement is not effective until NovemberTerm Note funded in full on October 1, 2017, with the monthly2021.
Roanoke Gas also has other unsecured notes at varying fixed interest rate on the note floating until the swap period begins. The proceeds from the note were used to convert a portion of the Company's line-of-credit balance into longer-term financing.
Midstream has two unsecured Promissory Notes ("Notes") which provide up to a total of $25 million in borrowing limits over a period of 5 years, with an interest other variable rate of 30-day LIBOR plus 160 basis points. Midstream issued the Notes in December 2015 to provide financing for capital investment in respect of its 1% interestnotes in the LLC. In accordance withoriginal principal amounts of $14 million and $10 million that are hedged by swap agreements, which effectively convert the terms of the debt, at such point in time as Midstream has borrowed $17.5 million under the Notes, Midstream is requiredinterest rates to provide the next $5 million towards its capital contributions to the LLC. Once Midstream has completed its $5 million in contributions, it may resume borrowing under the Notes up to the $25 million limit.3.24% and 3.14%, respectively.
Long-term debt consists of the following:
| September 30 | ||||||||||||||||
| 2017 | 2016 | |||||||||||||||
| Principal | Unamortized Debt Issuance Costs | Principal | Unamortized Debt Issuance Costs | |||||||||||||
| Roanoke Gas Company: | ||||||||||||||||
| Unsecured senior notes payable, at 4.26%, due on September 18, 2034 | $ | 30,500,000 | $ | 164,119 | $ | 30,500,000 | $ | 173,773 | ||||||||
| Unsecured term note payable, at 30-day LIBOR plus 0.90%, November 1, 2021 | 7,000,000 | 13,618 | — | — | ||||||||||||
| Pending unsecured note | — | 48,160 | — | — | ||||||||||||
| RGC Midstream, LLC: | ||||||||||||||||
| Unsecured term notes payable, at 30-day LIBOR plus 1.60% due December 29, 2020 | $ | 6,312,200 | $ | 66,052 | $ | 3,396,200 | $ | 86,376 | ||||||||
| Total notes payable | $ | 43,812,200 | $ | 291,949 | $ | 33,896,200 | $ | 260,149 | ||||||||
| Line-of-credit, at 30-day LIBOR plus 1.00%, due March 31, 2019 | 17,791,760 | — | — | — | ||||||||||||
| Total long-term debt | $ | 61,603,960 | $ | 291,949 | $ | 33,896,200 | $ | 260,149 | ||||||||
September 30 | ||||||||||||||||
2022 | 2021 | |||||||||||||||
Principal | Unamortized Debt Issuance Costs | Principal | Unamortized Debt Issuance Costs | |||||||||||||
Roanoke Gas: | ||||||||||||||||
Unsecured senior notes payable, at 4.26%, due September 18, 2034 | $ | 30,500,000 | $ | 115,849 | $ | 30,500,000 | $ | 125,502 | ||||||||
Unsecured term note payable, at 30-day LIBOR plus 0.90%, due November 1, 2021 | — | — | 7,000,000 | 278 | ||||||||||||
Unsecured term notes payable, at 3.58% due October 2, 2027 | 8,000,000 | 24,080 | 8,000,000 | 28,896 | ||||||||||||
Unsecured term notes payable at 4.41%, due March 28, 2031 | 10,000,000 | 26,627 | 10,000,000 | 29,760 | ||||||||||||
Unsecured term notes payable at 3.60%, due December 6, 2029 | 10,000,000 | 25,539 | 10,000,000 | 29,062 | ||||||||||||
Unsecured term note payable, a 30-day SOFR plus 1.20%, due August 20, 2026 | 15,000,000 | — | — | — | ||||||||||||
Unsecured term note payable, at 30-day LIBOR plus 1.00%, due October 1, 2028 | 10,000,000 | 28,674 | — | 21,545 | ||||||||||||
Midstream: | ||||||||||||||||
Unsecured term notes payable, at TERM SOFR plus 1.50% due December 31, 2023 | 21,896,200 | 18,553 | 33,610,200 | 14,904 | ||||||||||||
Unsecured term note payable, at 30-day LIBOR plus 1.15%, due June 12, 2026 | 14,000,000 | 9,029 | 14,000,000 | 11,437 | ||||||||||||
Unsecured term note payable, at 30-day LIBOR plus 1.20%, due June 1, 2024 | 9,875,000 | 3,929 | 10,000,000 | 6,286 | ||||||||||||
Unsecured term note payable, at 30-day LIBOR plus 1.15%, due January 1, 2028 | 8,000,000 | 23,631 | — | — | ||||||||||||
Total notes payable, current and noncurrent | $ | 137,271,200 | $ | 275,911 | $ | 123,110,200 | $ | 267,670 | ||||||||
Line-of-credit, at 30-day LIBOR plus 1.00%, due March 31, 2023 | — | — | 17,628,897 | — | ||||||||||||
Total long-term debt | $ | 137,271,200 | $ | 275,911 | $ | 140,739,097 | $ | 267,670 | ||||||||
Less: current maturities of long-term debt | (1,300,000 | ) | — | (7,000,000 | ) | — | ||||||||||
Total long-term debt, net current maturities | $ | 135,971,200 | $ | 275,911 | $ | 133,739,097 | $ | 267,670 | ||||||||
The line-of-credit referenced in the table above was replaced in March 2022 and is now classified as a short-term instrument. See Note 6 for additional information.
Debt issuance costs are amortized over the life of the related debt. As of September 30, 20172022 and 2016,2021, the Company also had an unamortized loss on the early retirement of debt of $1,941,182$1,370,246 and $2,055,369,$1,484,433, respectively, which has been deferred as a regulatory asset and is being amortized over a 20 year period.
All of the debt agreements set forth certain representations, warranties and covenants to which the Company is subject, including financial covenants that limit Consolidated Long-Term Indebtednessconsolidated long-term indebtedness to not more than 65% of total capitalization. All of the debt agreements except for the line-of-credit provide for priority indebtedness to not exceed 15% of consolidated total assets.
The aggregate annual maturities of long-term debt for the next five years ending after September 30, 20172022 are as follows:
Year Ending September 30 | Maturities | |||
2023 | $ | 1,300,000 | ||
2024 | 32,871,200 | |||
2025 | 1,600,000 | |||
2026 | 30,600,000 | |||
2027 | 1,600,000 | |||
Thereafter | 69,300,000 | |||
Total | $ | 137,271,200 | ||
| Year Ending September 30 | Maturities | ||
| 2018 | $ | — | |
| 2019 | 17,791,760 | ||
| 2020 | — | ||
| 2021 | 6,312,200 | ||
| 2022 | 7,000,000 | ||
| Thereafter | 30,500,000 | ||
| Total | $ | 61,603,960 | |
8. | |
INCOME TAXES |
The Company accounts for income taxes pursuant to the provisions of ASC 740,Income Taxes,which requires, among other things, an asset and liability approach to calculating deferred income taxes. The asset and liability approach requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the carrying amounts and the tax bases of assets and liabilities.
Under the provisions of ASC 740, the deferred tax assets and liabilities of the Company were revalued in fiscal 2018 to reflect the reduction in the corporate federal income tax rate. As a result of the revaluation, the excess deferred income taxes of the regulated operations of Roanoke Gas were reclassified to a regulatory liability. The excess deferred taxes related to the depreciable property are being returned to customers through reduced billings over the remaining weighted average useful life of the property with a corresponding reduction in income tax expense. The excess deferred taxes related to the other regulatory basis differences are being collected from customers over a five year period.
During fiscal 2022 and 2021, the Company engaged an outside firm to conduct a study of its activities that would qualify for the Research and Development ("R&D") credit under 26 U.S. Code § 41- Credit for increasing research activities. Upon completion of the 2021 study, the Company filed amended federal income tax returns for the 2017,2018 and 2019 fiscal years to claim the R&D tax credit, as well as filed for the R&D tax credit on its fiscal 2020 federal income tax return. The total credits claimed on the income tax returns amounted to $3,169,656, which was offset by an increase of $636,694 in income tax resulting from the add back to taxable income of an amount equal to the total tax credits claimed for the 2017,2018 and 2019 fiscal years. During 2022, the Company filed for the R&D tax credit on its fiscal 2021 federal income tax return. The total credits claimed on the fiscal 2021 income tax return amounted to $659,920. The Company deferred the tax credits as a regulatory liability because they related to utility plant. These credits are being amortized over the 20 year tax-life of the related utility plant. A portion of these tax credits were generated as a result of expenditures that qualify under the SAVE Plan and are subject to return to customers through a reduction in the corresponding SAVE rates in future periods. The Company recognized $165,652 of amortization as part of income tax expense on the consolidated statements of income in fiscal 2022 related to the federal R&D tax credits. No amortization was recognized in fiscal 2021.
During fiscal 2022 and 2021, the Company also applied for a Virginia State tax credit related to the R&D study for its fiscal 2021 and 2020 tax years, respectively. The total credits claimed on the fiscal 2021 tax return amounted to $51,398. Consistent with the treatment of the federal tax credits, the Company deferred the tax credits as a regulatory liability, which are being amortized over the 20 year tax-life of the related utility plant. The amount related to the 2021 tax study to be claimed on the fiscal 2022 tax return has not yet been determined and therefore is not included in the consolidated financial statements at this time. The Company recognized $5,212 of amortization as part of income tax expense on the consolidated statements of income in fiscal 2022 related to the state R&D tax credits. No amortization was recognized in fiscal 2021.
The details of income tax expense (benefit) are as follows:
| Years Ended September 30 | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
| Current income taxes: | ||||||||||||
| Federal | $ | 72,368 | $ | (1,216,745 | ) | $ | 379,180 | |||||
| State | 407,643 | 415,975 | 374,541 | |||||||||
| Total current income taxes | 480,011 | (800,770 | ) | 753,721 | ||||||||
| Deferred income taxes: | ||||||||||||
| Federal | 3,129,925 | 4,302,906 | 2,289,729 | |||||||||
| State | 195,454 | 164,048 | 127,112 | |||||||||
| Total deferred income taxes | 3,325,379 | 4,466,954 | 2,416,841 | |||||||||
| Total income tax expense | $ | 3,805,390 | $ | 3,666,184 | $ | 3,170,562 | ||||||
Years Ended September 30 | ||||||||
2022 | 2021 | |||||||
Current income taxes: | ||||||||
Federal | $ | 2,494,942 | $ | 2,527,997 | ||||
State | 523,571 | 569,877 | ||||||
Total current income taxes | 3,018,513 | 3,097,874 | ||||||
Deferred income taxes: | ||||||||
Federal | (11,160,425 | ) | (137,159 | ) | ||||
State | (3,097,869 | ) | 243,347 | |||||
Total deferred income taxes | (14,258,294 | ) | 106,188 | |||||
Amortization of R&D tax credits: | ||||||||
Federal | (165,652 | ) | — | |||||
State | (5,212 | ) | — | |||||
Total amortization of R&D tax credits | (170,864 | ) | — | |||||
Total income tax expense (benefit) | $ | (11,410,645 | ) | $ | 3,204,062 | |||
Income tax expense for the years ended September 30, 2017, 20162022 and 20152021 differed from amounts computed by applying the U.S. Federalfederal income tax rate of 34% to earnings before income taxes due to the following:
Years Ended September 30 | ||||||||
2022 | 2021 | |||||||
Income (loss) before income taxes | $ | (43,143,247 | ) | $ | 13,306,124 | |||
Corporate federal income tax rate | 21 | % | 21 | % | ||||
Income tax expense (benefit) computed at the federal statutory rate | $ | (9,060,082 | ) | $ | 2,794,286 | |||
State income taxes, net of federal income tax benefit | (2,033,695 | ) | 642,447 | |||||
Net amortization of excess deferred taxes on regulated operations | (162,228 | ) | (162,228 | ) | ||||
Tax on other permanent differences | 32,914 | 13,321 | ||||||
Tax benefit recognized on stock compensation | (27,191 | ) | (4,099 | ) | ||||
Amortization of R&D tax credits | (170,864 | ) | — | |||||
Tax credits | — | (86,839 | ) | |||||
Other, net | 10,501 | 7,174 | ||||||
Total income tax expense (benefit) | $ | (11,410,645 | ) | $ | 3,204,062 | |||
| Years Ended September 30 | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
| Income before income taxes | $ | 10,038,255 | $ | 9,473,050 | $ | 8,264,977 | ||||||
| Income tax expense computed at the federal statutory rate | $ | 3,413,007 | $ | 3,220,837 | $ | 2,810,092 | ||||||
| State income taxes, net of federal income tax benefit | 398,044 | 382,815 | 331,091 | |||||||||
| Other, net | (5,661 | ) | 62,532 | 29,379 | ||||||||
| Total income tax expense | $ | 3,805,390 | $ | 3,666,184 | $ | 3,170,562 | ||||||
The tax effects of temporary differences that give rise to the deferred tax assets and deferred tax liabilities are as follows:
| September 30 | ||||||||
| 2017 | 2016 | |||||||
| Deferred tax assets: | ||||||||
| Allowance for uncollectibles | $ | 37,752 | $ | 29,203 | ||||
| Accrued pension and postretirement medical benefits | 1,747,429 | 2,532,672 | ||||||
| Accrued vacation | 239,414 | 262,273 | ||||||
| Over-recovery of gas costs | 545,894 | 345,318 | ||||||
| Costs of gas held in storage | 1,009,206 | 1,077,849 | ||||||
| Deferred compensation | 824,281 | 770,868 | ||||||
| Other | 348,833 | 340,121 | ||||||
| Total gross deferred tax assets | 4,752,809 | 5,358,304 | ||||||
| Deferred tax liabilities: | ||||||||
| Utility plant | 27,630,486 | 24,264,165 | ||||||
| MVP investment | 154,817 | 40,776 | ||||||
| Other | 44,354 | 11,217 | ||||||
| Total gross deferred tax liabilities | 27,829,657 | 24,316,158 | ||||||
| Net deferred tax liability | $ | 23,076,848 | $ | 18,957,854 | ||||
September 30 | ||||||||
2022 | 2021 | |||||||
Deferred tax assets: | ||||||||
Allowance for credit losses | $ | 95,564 | $ | 62,292 | ||||
Accrued pension and postretirement medical benefits | 486,745 | 195,044 | ||||||
Regulatory effect of change in federal income tax rate | 2,708,809 | 2,761,667 | ||||||
Accrued paid time off | 150,075 | 137,175 | ||||||
Cost of gas held in storage | 702,040 | 753,344 | ||||||
Deferred compensation | 993,079 | 915,749 | ||||||
Interest rate swaps | — | 307,873 | ||||||
Accrued gas cost | 125,888 | 289,801 | ||||||
MVP impairment | 14,180,759 | — | ||||||
Other | 124,034 | 98,642 | ||||||
Total gross deferred tax assets | 19,566,993 | 5,521,587 | ||||||
Deferred tax liabilities: | ||||||||
Utility property | 19,074,085 | 18,643,863 | ||||||
MVP investment | 1,366,157 | 1,825,937 | ||||||
Interest rate swaps | 1,235,126 | — | ||||||
Total gross deferred tax liabilities | 21,675,368 | 20,469,800 | ||||||
Net deferred tax asset | 1,057,079 | — | ||||||
Net deferred tax liability | $ | 3,165,454 | $ | 14,948,213 | ||||
Deferred tax expense for fiscal 2016 reflected the effect of 50% bonus depreciation for the entire fiscal year 2016 as well as for nine months of fiscal 2015. The Protecting Americans from Tax Hikes (PATH Act), which extended 50% bonus depreciation for calendar 2015, was signed into law on December 18, 2015, subsequent to the issuance of the Company's September 30, 2015 annual report. As a result, $1,283,925 of deferred taxes that related to fiscal 2015 bonus depreciation were reflected in the fiscal 2016 tax provision, thereby reducing the current tax expense and increasing deferred tax expense by the same amount. The same situation occurred in fiscal 2014 when the extension of 50% bonus depreciation was not signed into law until December 19, 2014, following the issuance of the Company's financial statements for the year ended September 30, 2014. Correspondingly, fiscal 2015 income tax expense included the tax effect of the 50% bonus depreciation for fixed asset additions during the last nine months of fiscal 2014, which resulted in $1,442,211 in deferred tax expense related to fiscal 2014 being included in fiscal 2015. The recording of the effect of the adjustments for bonus depreciation had no effect on total income tax expense, net income or earnings per share. Only the current and deferred components of income tax expense and their corresponding assets and liabilities were affected.
ASC No. 740 -
The Company files a consolidated federal income tax return and state income tax returns in Virginia and West Virginia.Virginia, and thus subject to examinations by federal and state tax authorities. The IRS is currently examining the Company's 2018 and 2019 federal tax returns. The Company does not have any indication at this time of the outcome. The Company believes its income tax assets and liabilities are fairly stated as of September 30, 2022 and 2021, however, these assets and liabilities could be adjusted as a result of this examination. With the amendment of the federal returns for fiscal 2017,2018 and 2019, these years will remain open for IRS examination for two more years. Aside from these exceptions, the federal returns and the state returns for both Virginia and West Virginia for the tax years ended prior to September 30, 20142017 are no longer subject to examination.
9. | |
EMPLOYEE BENEFIT PLANS |
The Company sponsors both a noncontributory defined benefit pension plan ("pension plan") and a postretirement benefit plan ("postretirement plan").plan. The pension plan covers substantially all employees hired prior to January 2017 and benefits fully vest after 5 years of credited service. Benefits paid to retirees are based on age at retirement, years of service and average compensation. In November 2016, the Board of Directors approved Effective January 1, 2017, a "soft freeze" to the pension plan whereby nowas implemented, and employees hired on or after January 1, 2017 will bethat date are no longer eligible to participate. Employees hired prior to January 1, 2017
The postretirement benefit plan provides certain health care, supplemental retirement and life insurance benefits to retired employees who meet specific age and service requirements. Employees hired prior to January 1,2000 are eligible to participate in the postretirement benefit plan. Employees must have a minimum of 10 years of service and retire after attaining the age of 55 in order to vest in the postretirement plan. Retiree contributions to the plan are based on the number of years of service to the Company as determined under the defined benefitpension plan.
Employers who sponsor defined benefit plans must recognize the funded status of defined benefit pension and other postretirement plans as an asset or liability in their statements of financial position and recognize changes in that funded status in the year in which the changes occur through comprehensive income. For pension plans, the benefit obligation is the projected benefit obligation, and for other postretirement plans, the benefit obligation is the accumulated benefit obligation. The Company established a regulatory asset for the portion of the obligation expected to be recovered inthrough rates in future periods. The regulatory asset is adjusted for the amortization of the transition obligation and recognition of actuarial gains and losses. The portion of the obligation attributable to the unregulated operations of the holding company is recognized in other comprehensive income.
The following tables settable sets forth the benefit obligation, fair value of plan assets, the funded status of the benefit plans, and amounts recognized in the Company’s consolidated financial statements and the assumptions used.
| Pension Plan | Postretirement Plan | |||||||||||||||
| 2017 | 2016 | 2017 | 2016 | |||||||||||||
| Accumulated benefit obligation | $ | 25,481,993 | $ | 25,090,968 | $ | 17,666,812 | $ | 18,504,710 | ||||||||
| Change in benefit obligation: | ||||||||||||||||
| Benefit obligation at beginning of year | $ | 29,494,950 | $ | 27,167,621 | $ | 18,504,710 | $ | 15,355,668 | ||||||||
| Service cost | 706,677 | 694,375 | 183,267 | 148,018 | ||||||||||||
| Interest cost | 995,598 | 1,132,776 | 626,822 | 624,579 | ||||||||||||
| Actuarial (gain) loss | (824,361 | ) | 2,440,957 | (1,199,722 | ) | 2,812,516 | ||||||||||
| Benefit payments, net of retiree contributions | (715,517 | ) | (1,940,779 | ) | (448,265 | ) | (436,071 | ) | ||||||||
| Benefit obligation at end of year | $ | 29,657,347 | $ | 29,494,950 | $ | 17,666,812 | $ | 18,504,710 | ||||||||
| Change in fair value of plan assets: | ||||||||||||||||
| Fair value of plan assets at beginning of year | $ | 23,113,057 | $ | 21,394,399 | $ | 11,122,783 | $ | 10,443,629 | ||||||||
| Actual return on plan assets, net of taxes | 3,021,131 | 2,159,437 | 1,016,644 | 615,225 | ||||||||||||
| Employer contributions | 1,000,000 | 1,500,000 | 1,000,000 | 500,000 | ||||||||||||
| Benefit payments, net of retiree contributions | (715,517 | ) | (1,940,779 | ) | (448,265 | ) | (436,071 | ) | ||||||||
| Fair value of plan assets at end of year | $ | 26,418,671 | $ | 23,113,057 | $ | 12,691,162 | $ | 11,122,783 | ||||||||
| Funded status | $ | (3,238,676 | ) | $ | (6,381,893 | ) | $ | (4,975,650 | ) | $ | (7,381,927 | ) | ||||
| Amounts recognized in the balance sheets consist of: | ||||||||||||||||
| Noncurrent liabilities | $ | (3,238,676 | ) | $ | (6,381,893 | ) | $ | (4,975,650 | ) | $ | (7,381,927 | ) | ||||
| Amounts recognized in accumulated other comprehensive loss: | ||||||||||||||||
| Net actuarial loss, net of tax | $ | 572,740 | $ | 1,583,345 | $ | 702,013 | $ | 913,886 | ||||||||
| Total amounts included in other comprehensive loss, net of tax | $ | 572,740 | $ | 1,583,345 | $ | 702,013 | $ | 913,886 | ||||||||
| Amounts deferred to a regulatory asset: | ||||||||||||||||
| Net actuarial loss | $ | 5,471,547 | $ | 6,732,800 | $ | 3,830,763 | $ | 5,563,642 | ||||||||
| Amounts recognized as regulatory assets | $ | 5,471,547 | $ | 6,732,800 | $ | 3,830,763 | $ | 5,563,642 | ||||||||
Pension Plan | Postretirement Plan | |||||||||||||||
2022 | 2021 | 2022 | 2021 | |||||||||||||
Accumulated benefit obligation | $ | 24,776,968 | $ | 33,341,841 | $ | 12,416,546 | $ | 16,796,849 | ||||||||
Change in benefit obligation: | ||||||||||||||||
Benefit obligation at beginning of year | $ | 37,654,468 | $ | 39,998,002 | $ | 16,796,849 | $ | 17,925,409 | ||||||||
Service cost | 648,289 | 734,282 | 97,802 | 140,691 | ||||||||||||
Interest cost | 1,013,115 | 975,139 | 443,721 | 430,490 | ||||||||||||
Actuarial gain | (10,862,957 | ) | (2,237,486 | ) | (4,330,387 | ) | (1,109,181 | ) | ||||||||
Benefit payments, net of retiree contributions | (1,184,459 | ) | (1,815,469 | ) | (591,439 | ) | (590,560 | ) | ||||||||
Benefit obligation at end of year | $ | 27,268,456 | $ | 37,654,468 | $ | 12,416,546 | $ | 16,796,849 | ||||||||
Change in fair value of plan assets: | ||||||||||||||||
Fair value of plan assets at beginning of year | $ | 38,914,107 | $ | 37,657,631 | $ | 15,882,342 | $ | 14,116,253 | ||||||||
Actual return on plan assets, net of taxes | (9,711,851 | ) | 2,571,945 | (3,152,784 | ) | 1,956,649 | ||||||||||
Employer contributions | — | 500,000 | — | 400,000 | ||||||||||||
Benefit payments, net of retiree contributions | (1,184,459 | ) | (1,815,469 | ) | (591,439 | ) | (590,560 | ) | ||||||||
Fair value of plan assets at end of year | $ | 28,017,797 | $ | 38,914,107 | $ | 12,138,119 | $ | 15,882,342 | ||||||||
Funded status | $ | 749,341 | $ | 1,259,639 | $ | (278,427 | ) | $ | (914,507 | ) | ||||||
Amounts recognized in the consolidated balance sheet consist of: | ||||||||||||||||
Noncurrent assets | $ | 749,341 | $ | 1,259,639 | $ | — | $ | — | ||||||||
Noncurrent liabilities | — | — | (278,427 | ) | (914,507 | ) | ||||||||||
Amounts recognized in accumulated other comprehensive loss: | ||||||||||||||||
Net actuarial loss, net of tax | $ | 1,243,889 | $ | 527,720 | $ | 355,088 | $ | 119,504 | ||||||||
Total amounts included in accumulated other comprehensive loss, net of tax | $ | 1,243,889 | $ | 527,720 | $ | 355,088 | $ | 119,504 | ||||||||
Amounts deferred to a regulatory asset: | ||||||||||||||||
Net actuarial loss (gain) | $ | 4,132,472 | $ | 4,562,834 | $ | (30,118 | ) | $ | 798,558 | |||||||
Amounts recognized as regulatory assets (liabilities) | $ | 4,132,472 | $ | 4,562,834 | $ | (30,118 | ) | $ | 798,558 | |||||||
During 2016,fiscal 2021, the Company offered a one-time,one-time, lump sum pay out option for vested, terminated employees not currently receiving payments under the pension plan. The lump sum offer was accepted by 4017 eligible participants resulting in a distribution of the 63 eligible participants. In September 2016, the pension$717,197 in plan distributed $1,241,529 to the participants electing to receive the lump sum payments, which resulted inassets with a corresponding reduction of approximately $1,500,000 in the projected pensionbenefit plan obligation.
The Company expects that approximately $24,000$79,000, before tax, of accumulated other comprehensive incomeAOCI will be recognized as a reduction in net periodic benefit costs in fiscal 20182023 and approximately $659,000$238,000 of amounts deferred as regulatory assets will be amortized and recognized in net periodic benefit costs in fiscal 2018.2023.
The reduction in the benefit obligations for both the pension plan and postretirement plan was primarily attributed to actuarial gains resulting from the increase in the discount rate used to calculate the benefit obligations.
The following table details the actuarial assumptions used in determining the projected benefit obligations and net benefit cost of the pension plan and the accumulated benefit obligations and net benefit cost of the postretirement plan for 2017, 2016 and 2015.
| Pension Plan | Postretirement Plan | |||||||||||||||||
| 2017 | 2016 | 2015 | 2017 | 2016 | 2015 | |||||||||||||
| Assumptions used to determine benefit obligations: | ||||||||||||||||||
| Discount rate | 3.72 | % | 3.42 | % | 4.22 | % | 3.69 | % | 3.33 | % | 4.15 | % | ||||||
| Expected rate of compensation increase | 4.00 | % | 4.00 | % | 4.00 | % | N/A | N/A | N/A | |||||||||
| Assumptions used to determine benefit costs: | ||||||||||||||||||
| Discount rate | 3.42 | % | 4.22 | % | 4.22 | % | 3.33 | % | 4.15 | % | 4.10 | % | ||||||
| Expected long-term rate of return on plan assets | 7.00 | % | 7.00 | % | 7.00 | % | 4.84 | % | 4.89 | % | 4.90 | % | ||||||
| Expected rate of compensation increase | 4.00 | % | 4.00 | % | 4.00 | % | N/A | N/A | N/A | |||||||||
Pension Plan | Postretirement Plan | |||||||||||||||
2022 | 2021 | 2022 | 2021 | |||||||||||||
Assumptions used to determine benefit obligations: | ||||||||||||||||
Discount rate | 5.15 | % | 2.73 | % | 5.16 | % | 2.70 | % | ||||||||
Expected rate of compensation increase | 4.00 | % | 4.00 | % | N/A | N/A | ||||||||||
Assumptions used to determine benefit costs: | ||||||||||||||||
Discount rate | 2.73 | % | 2.47 | % | 2.70 | % | 2.44 | % | ||||||||
Expected long-term rate of return on plan assets | 4.75 | % | 5.40 | % | 4.24 | % | 4.25 | % | ||||||||
Expected rate of compensation increase | 4.00 | % | 4.00 | % | N/A | N/A | ||||||||||
To develop the expected long-term rate of return on assets assumption, the Company, with input from the plans'Plans' actuaries and investment advisors, considered the historical returns and the future expectations for returns for each asset class, as well as the target asset allocation of each plan’s portfolio.
Components of net periodic benefit cost are as follows:
| Pension Plan | Postretirement Plan | |||||||||||||||||||||||
| 2017 | 2016 | 2015 | 2017 | 2016 | 2015 | |||||||||||||||||||
| Service cost | $ | 706,677 | $ | 694,375 | $ | 654,782 | $ | 183,267 | $ | 148,018 | $ | 167,580 | ||||||||||||
| Interest cost | 995,598 | 1,132,776 | 1,025,908 | 626,822 | 624,579 | 600,096 | ||||||||||||||||||
| Expected return on plan assets | (1,616,412 | ) | (1,492,241 | ) | (1,440,846 | ) | (571,513 | ) | (507,858 | ) | (516,656 | ) | ||||||||||||
| Recognized loss | 662,180 | 501,678 | 257,378 | 429,758 | 250,173 | 197,058 | ||||||||||||||||||
| Net periodic benefit cost | $ | 748,043 | $ | 836,588 | $ | 497,222 | $ | 668,334 | $ | 514,912 | $ | 448,078 | ||||||||||||
Pension Plan | Postretirement Plan | |||||||||||||||
2022 | 2021 | 2022 | 2021 | |||||||||||||
Service cost | $ | 648,289 | $ | 734,282 | $ | 97,802 | $ | 140,691 | ||||||||
Interest cost | 1,013,115 | 975,139 | 443,721 | 430,490 | ||||||||||||
Expected return on plan assets | (1,831,550 | ) | (2,015,743 | ) | (666,167 | ) | (596,488 | ) | ||||||||
Recognized loss | 146,402 | 502,141 | — | 154,659 | ||||||||||||
Net periodic benefit cost | $ | (23,744 | ) | $ | 195,819 | $ | (124,644 | ) | $ | 129,352 | ||||||
Service cost is included in operations and maintenance expense in the consolidated statements of income. All other components of net periodic benefit costs are included in other income, net in the consolidated statements of income.
The assumed health care cost trend rates used in measuring the accumulated benefit obligation for the postretirement medical plan as of September 30, 2017, 2016 and 2015 are presented below:
| Pre 65 | Post 65 | |||||||||||||||||
| 2017 | 2016 | 2015 | 2017 | 2016 | 2015 | |||||||||||||
| Health care cost trend rate assumed for next year | 7.00 | % | 7.50 | % | 8.00 | % | 5.00 | % | 5.00 | % | 5.00 | % | ||||||
| Rate to which the cost trend is assumed to decline (the ultimate trend rate) | 5.00 | % | 5.00 | % | 5.00 | % | 5.00 | % | 5.00 | % | 5.00 | % | ||||||
| Year that the rate reaches the ultimate trend rate | 2021 | 2021 | 2021 | 2017 | 2016 | 2015 | ||||||||||||
Pre 65 | Post 65 | |||||||||||||||
2022 | 2021 | 2022 | 2021 | |||||||||||||
Health care cost trend rate assumed for next year | 6.00 | % | 6.50 | % | 5.20 | % | 5.20 | % | ||||||||
Rate to which the cost trend is assumed to decline (the ultimate trend rate) | 5.20 | % | 5.50 | % | 5.20 | % | 5.20 | % | ||||||||
Year that the rate reaches the ultimate trend rate | 2025 | 2023 | 2022 | 2021 | ||||||||||||
The health care cost trend rate assumptions could have a significant effect on the amounts reported. A change of 1% would have the following effects:
1% Increase | 1% Decrease | |||||||
Effect on total service and interest cost components | $ | 93,000 | $ | (75,000 | ) | |||
Effect on accumulated postretirement benefit obligation | 1,536,000 | (1,293,000 | ) | |||||
| 1% Increase | 1% Decrease | |||||||
| Effect on total service and interest cost components | $ | 153,000 | $ | (121,000 | ) | |||
| Effect on accumulated postretirement benefit obligation | 2,961,000 | (2,385,000 | ) | |||||
The primary objectives of the Plan’sboth plans' investment policypolicies are to maintain investment portfolios that diversify risk through prudent asset allocation parameters, achieve asset returns that meet or exceed the plans’corresponding actuarial assumptions achieve asset returns that are competitive with like institutions employing similar investment strategies and meet expected future benefits in both the short-term and long-term. The investment policyCompany's pension plan allocation approach seeks to match the duration of the fixed income portion of the portfolio with the duration of the plan's liabilities. Such a match is designed to reduce the overall volatility in the pension plan relative to the funded status. The 30% equity allocation in the pension plan provides for a rangepotential returns to offset growth in the liabilities as eligible participants continue to accrue benefits.
Based on its most recent evaluation of returns for the asset classes within each plan's investment allocations to allow for flexibility in responding to market conditions. The investment policy is periodically reviewed byportfolio, the Company set the expected long-term rate of return for the pension plan and a third-party investment advisor.
The Company’s target and actual asset allocation in the pension and postretirement benefit plans as of September 30, 20172022 and 20162021 were:
| Pension Plan | Postretirement Plan | |||||||||||||||||
| Target | 2017 | 2016 | Target | 2017 | 2016 | |||||||||||||
| Asset category: | ||||||||||||||||||
| Equity securities | 60 | % | 63 | % | 63 | % | 50 | % | 51 | % | 52 | % | ||||||
| Debt securities | 40 | % | 36 | % | 36 | % | 50 | % | 48 | % | 47 | % | ||||||
| Cash | — | % | 1 | % | 1 | % | — | % | 1 | % | — | % | ||||||
| Other | — | % | — | % | — | % | — | % | — | % | 1 | % | ||||||
Pension Plan | Postretirement Plan | |||||||||||||||||||||||
Target | 2022 | 2021 | Target | 2022 | 2021 | |||||||||||||||||||
Asset category: | ||||||||||||||||||||||||
Equity securities | 30 | % | 13 | % | 30 | % | 50 | % | 48 | % | 49 | % | ||||||||||||
Debt securities | 70 | % | — | % | 69 | % | 50 | % | 51 | % | 50 | % | ||||||||||||
Cash | — | % | 87 | % | 1 | % | — | % | 1 | % | 1 | % | ||||||||||||
Other | — | % | — | % | — | % | — | % | — | % | — | % | ||||||||||||
The plans assets of the plans are invested in mutual funds and common and collective investment trust ("CIT") funds that function like mutual funds. On September 30, 2022, the Company was in the process of transitioning to new investment advisors for the pension plan. The mutual funds in the pension plan were unaffected by this change; however, the CITs were required to be re-registered and assigned new account numbers. As a result, the CIT funds were liquidated on September 30, 2022 and reinvested in the same investments on October 3, 2022. Absent the re-registration process, the investment allocation would have been 29% equity, 70% fixed income and 1% cash on September 30, 2022.
The Company uses the fair value hierarchy described in Note 1 to classify these assets. The mutual funds are included under Level 21 in the fair value hierarchy as their fair values are determined based on individual prices for each security that comprises the mutual funds. Most of the individual investments are determined based on quoted marketnet asset values of the shares held in the investments in the plans. The CIT funds are included under Level 2 as these investments have observable Level 2 pricing inputs, including quoted prices for each security; however, certain fixed income securities and other investmentssimilar assets in active or non-active markets. While the underlying asset values are quoted prices, the net asset value of a unit in these funds is not actively traded and are valued based on similar investments. publicly quoted. The following table containstables contain the fair value classifications of the benefit planplans' assets:
Pension Plan | ||||||||||||||||
Fair Value Measurements - September 30, 2022 | ||||||||||||||||
Fair Value | Level 1 | Level 2 | Level 3 | |||||||||||||
Asset Class: | ||||||||||||||||
Cash | $ | 24,312,969 | $ | 24,312,969 | $ | — | $ | — | ||||||||
Common and Collective Trust and Pooled Funds: | ||||||||||||||||
Bonds | ||||||||||||||||
Liability Driven Investment | — | — | — | — | ||||||||||||
Equities | ||||||||||||||||
Domestic Large Cap Growth | — | — | — | — | ||||||||||||
Domestic Large Cap Value | — | — | — | — | ||||||||||||
Domestic Small/Mid Cap Core | — | — | — | — | ||||||||||||
Foreign Large Cap Value | — | — | — | — | ||||||||||||
Mutual Funds: | ||||||||||||||||
Equities | ||||||||||||||||
Domestic Large Cap Growth | 1,172,296 | 1,172,296 | — | — | ||||||||||||
Domestic Large Cap Value | 1,172,714 | 1,172,714 | — | — | ||||||||||||
Foreign Large Cap Growth | 486,184 | 486,184 | — | — | ||||||||||||
Foreign Large Cap Core | 873,634 | 873,634 | — | — | ||||||||||||
Foreign Large Cap Value | — | — | — | — | ||||||||||||
Total | $ | 28,017,797 | $ | 28,017,797 | $ | — | $ | — | ||||||||
| Defined Benefit Pension Plan Fair Value Measurements - September 30, 2017 | ||||||||||||||||
| Fair Value | Level 1 | Level 2 | Level 3 | |||||||||||||
| Asset Class: | ||||||||||||||||
| Cash | $ | 265,100 | $ | 265,100 | $ | — | $ | — | ||||||||
| Common and Collective Trust and Pooled Funds: | ||||||||||||||||
| Bonds | ||||||||||||||||
| Liability Driven Investment | 9,635,998 | — | 9,635,998 | — | ||||||||||||
| Equities | ||||||||||||||||
| Domestic Large Cap Growth | 5,068,282 | — | 5,068,282 | — | ||||||||||||
| Domestic Large Cap Value | 5,046,530 | — | 5,046,530 | — | ||||||||||||
| Domestic Small/Mid Cap Core | 2,393,221 | — | 2,393,221 | — | ||||||||||||
| Foreign Large Cap Value | 2,139,733 | — | 2,139,733 | — | ||||||||||||
| Mutual Funds: | ||||||||||||||||
| Bonds | ||||||||||||||||
| Equities | ||||||||||||||||
| Foreign Large Cap Growth | 399,909 | — | 399,909 | — | ||||||||||||
| Foreign Large Cap Value | 398,995 | — | 398,995 | — | ||||||||||||
| Foreign Large Cap Core | 1,070,903 | — | 1,070,903 | — | ||||||||||||
| Total | $ | 26,418,671 | $ | 265,100 | $ | 26,153,571 | $ | — | ||||||||
| Defined Benefit Pension Plan Fair Value Measurements - September 30, 2016 | ||||||||||||||||
| Fair Value | Level 1 | Level 2 | Level 3 | |||||||||||||
| Asset Class: | ||||||||||||||||
| Cash | $ | 117,265 | $ | 117,265 | $ | — | $ | — | ||||||||
| Common and Collective Trust and Pooled Funds: | ||||||||||||||||
| Bonds | ||||||||||||||||
| Domestic Fixed Income | 4,497,373 | — | 4,497,373 | — | ||||||||||||
| Equities | ||||||||||||||||
| Domestic Large Cap Growth | 3,426,041 | — | 3,426,041 | — | ||||||||||||
| Domestic Large Cap Value | 4,543,385 | — | 4,543,385 | — | ||||||||||||
| Domestic Small/Mid Cap Core | 2,149,566 | — | 2,149,566 | — | ||||||||||||
| Foreign Large Cap Value | 1,795,897 | — | 1,795,897 | — | ||||||||||||
| Mutual Funds: | ||||||||||||||||
| Bonds | ||||||||||||||||
| Domestic Fixed Income | 3,615,209 | — | 3,615,209 | — | ||||||||||||
| Foreign Fixed Income | 234,622 | — | 234,622 | — | ||||||||||||
| Equities | ||||||||||||||||
| Domestic Large Cap Growth | 1,043,395 | — | 1,043,395 | — | ||||||||||||
| Foreign Large Cap Growth | 366,420 | — | 366,420 | — | ||||||||||||
| Foreign Large Cap Value | 373,480 | — | 373,480 | — | ||||||||||||
| Foreign Large Cap Core | 950,404 | — | 950,404 | — | ||||||||||||
| Total | $ | 23,113,057 | $ | 117,265 | $ | 22,995,792 | $ | — | ||||||||
Pension Plan | ||||||||||||||||
Fair Value Measurements - September 30, 2021 | ||||||||||||||||
Fair Value | Level 1 | Level 2 | Level 3 | |||||||||||||
Asset Class: | ||||||||||||||||
Cash | $ | 429,764 | $ | 429,764 | $ | — | $ | — | ||||||||
Common and Collective Trust and Pooled Funds: | ||||||||||||||||
Bonds | ||||||||||||||||
Liability Driven Investment | 26,898,651 | — | 26,898,651 | — | ||||||||||||
Equities | ||||||||||||||||
Domestic Large Cap Growth | 3,430,962 | — | 3,430,962 | — | ||||||||||||
Domestic Large Cap Value | 3,480,915 | — | 3,480,915 | — | ||||||||||||
Domestic Small/Mid Cap Core | 1,752,186 | — | 1,752,186 | — | ||||||||||||
Foreign Large Cap Value | 1,561,512 | — | 1,561,512 | — | ||||||||||||
Mutual Funds: | ||||||||||||||||
Equities | ||||||||||||||||
Foreign Large Cap Growth | 1,071,719 | 1,071,719 | — | — | ||||||||||||
Foreign Large Cap Value | 288,398 | 288,398 | — | — | ||||||||||||
Total | $ | 38,914,107 | $ | 1,789,881 | $ | 37,124,226 | $ | — | ||||||||
Postretirement Plan | ||||||||||||||||
Fair Value Measurements - September 30, 2022 | ||||||||||||||||
Fair Value | Level 1 | Level 2 | Level 3 | |||||||||||||
Asset Class: | ||||||||||||||||
Cash | $ | 75,219 | $ | 75,219 | $ | — | $ | — | ||||||||
Mutual Funds: | ||||||||||||||||
Bonds | ||||||||||||||||
Domestic Fixed Income | 5,644,954 | 5,644,954 | — | — | ||||||||||||
Foreign Fixed Income | 589,284 | 589,284 | — | — | ||||||||||||
Equities | ||||||||||||||||
Domestic Large Cap Growth | 1,698,421 | 1,698,421 | — | — | ||||||||||||
Domestic Large Cap Value | 1,793,746 | 1,793,746 | — | — | ||||||||||||
Domestic Small/Mid Cap Growth | 182,823 | 182,823 | — | — | ||||||||||||
Domestic Small/Mid Cap Value | 202,921 | 202,921 | — | — | ||||||||||||
Domestic Small/Mid Cap Core | 443,900 | 443,900 | — | — | ||||||||||||
Foreign Large Cap Growth | 469,659 | 469,659 | — | — | ||||||||||||
Foreign Large Cap Value | 462,196 | 462,196 | — | — | ||||||||||||
Foreign Large Cap Core | 574,996 | 574,996 | — | — | ||||||||||||
Total | $ | 12,138,119 | $ | 12,138,119 | $ | — | $ | — | ||||||||
| Postretirement Benefit Plan Fair Value Measurements - September 30, 2017 | ||||||||||||||||
| Fair Value | Level 1 | Level 2 | Level 3 | |||||||||||||
| Asset Class: | ||||||||||||||||
| Cash | $ | 64,616 | $ | 64,616 | $ | — | $ | — | ||||||||
| Mutual Funds | ||||||||||||||||
| Bonds | ||||||||||||||||
| Domestic Fixed Income | 5,727,258 | — | 5,727,258 | — | ||||||||||||
| Foreign Fixed Income | 359,460 | — | 359,460 | — | ||||||||||||
| Equities | ||||||||||||||||
| Domestic Large Cap Growth | 1,998,971 | — | 1,998,971 | — | ||||||||||||
| Domestic Large Cap Value | 1,998,714 | — | 1,998,714 | — | ||||||||||||
| Domestic Small/Mid Cap Growth | 209,332 | — | 209,332 | — | ||||||||||||
| Domestic Small/Mid Cap Value | 209,630 | — | 209,630 | — | ||||||||||||
| Domestic Small/Mid Cap Core | 455,867 | — | 455,867 | — | ||||||||||||
| Foreign Large Cap Growth | 39,107 | — | 39,107 | — | ||||||||||||
| Foreign Large Cap Value | 1,079,766 | — | 1,079,766 | — | ||||||||||||
| Foreign Large Cap Core | 511,298 | — | 511,298 | — | ||||||||||||
| Other | 37,143 | — | 37,143 | — | ||||||||||||
| Total | $ | 12,691,162 | $ | 64,616 | $ | 12,626,546 | $ | — | ||||||||
| Postretirement Benefit Plan Fair Value Measurements - September 30, 2016 | ||||||||||||||||
| Fair Value | Level 1 | Level 2 | Level 3 | |||||||||||||
| Asset Class: | ||||||||||||||||
| Cash | $ | 43,455 | $ | 43,455 | $ | — | $ | — | ||||||||
| Mutual Funds | ||||||||||||||||
| Bonds | ||||||||||||||||
| Domestic Fixed Income | 5,109,834 | — | 5,109,834 | — | ||||||||||||
| Foreign Fixed Income | 87,821 | — | 87,821 | — | ||||||||||||
| Equities | ||||||||||||||||
| Domestic Large Cap Growth | 1,824,796 | — | 1,824,796 | — | ||||||||||||
| Domestic Large Cap Value | 1,770,664 | — | 1,770,664 | — | ||||||||||||
| Domestic Small/Mid Cap Growth | 195,319 | — | 195,319 | — | ||||||||||||
| Domestic Small/Mid Cap Value | 198,884 | — | 198,884 | — | ||||||||||||
| Domestic Small/Mid Cap Core | 427,409 | — | 427,409 | — | ||||||||||||
| Foreign Large Cap Value | 964,827 | — | 964,827 | — | ||||||||||||
| Foreign Large Cap Core | 456,100 | — | 456,100 | — | ||||||||||||
| Other | 43,674 | — | 43,674 | — | ||||||||||||
| Total | $ | 11,122,783 | $ | 43,455 | $ | 11,079,328 | $ | — | ||||||||
Postretirement Plan | ||||||||||||||||
Fair Value Measurements - September 30, 2021 | ||||||||||||||||
Fair Value | Level 1 | Level 2 | Level 3 | |||||||||||||
Asset Class: | ||||||||||||||||
Cash | $ | 157,957 | $ | 157,957 | $ | — | $ | — | ||||||||
Mutual Funds: | ||||||||||||||||
Bonds | ||||||||||||||||
Domestic Fixed Income | 7,109,967 | 7,109,967 | — | — | ||||||||||||
Foreign Fixed Income | 757,422 | 757,422 | — | — | ||||||||||||
Equities | ||||||||||||||||
Domestic Large Cap Growth | 2,346,401 | 2,346,401 | — | — | ||||||||||||
Domestic Large Cap Value | 2,361,583 | 2,361,583 | — | — | ||||||||||||
Domestic Small/Mid Cap Growth | 295,628 | 295,628 | — | — | ||||||||||||
Domestic Small/Mid Cap Value | 248,317 | 248,317 | — | — | ||||||||||||
Domestic Small/Mid Cap Core | 557,739 | 557,739 | — | — | ||||||||||||
Foreign Large Cap Growth | 594,573 | 594,573 | — | — | ||||||||||||
Foreign Large Cap Value | 1,352,329 | 1,352,329 | — | — | ||||||||||||
Foreign Large Cap Core | 85,871 | 85,871 | — | — | ||||||||||||
Other | 14,555 | — | 14,555 | — | ||||||||||||
Total | $ | 15,882,342 | $ | 15,867,787 | $ | 14,555 | $ | — | ||||||||
Each mutual fund or common collective trust fund has been categorized based on its primary investment strategy.
Annual funding contributions to contribute $1,600,000 to itsthe pension plan and $600,000postretirement plan are made under advisement from the Company's actuaries and investment advisors based upon ERISA funding requirements. For the year ended September 30, 2022, no contributions were made to itsthe pension plan or postretirement benefitplan. The Company is not currently anticipating making any funding contributions to the pension plan or postretirement plan in fiscal 2018.
The following table reflects expected future benefit payments:
| Fiscal year ending September 30 | Pension Plan | Postretirement Plan | ||||||
| 2018 | $ | 817,861 | $ | 618,241 | ||||
| 2019 | 879,779 | 644,666 | ||||||
| 2020 | 966,930 | 671,228 | ||||||
| 2021 | 1,041,200 | 710,495 | ||||||
| 2022 | 1,139,637 | 749,674 | ||||||
| 2023-2027 | 6,981,849 | 4,148,403 | ||||||
Pension | Postretirement | |||||||
Fiscal year ending September 30 | Plan | Plan | ||||||
2023 | $ | 1,267,465 | $ | 787,890 | ||||
2024 | 1,327,549 | 748,788 | ||||||
2025 | 1,391,818 | 738,855 | ||||||
2026 | 1,474,728 | 734,466 | ||||||
2027 | 1,583,033 | 746,631 | ||||||
2028 - 2032 | 8,891,378 | 3,969,225 | ||||||
The Company alsoestablished an NQDC Plan in fiscal 2021. The NQDC Plan is an unfunded, nonqualified benefit plan offered to select members of senior management not eligible to participate in the pension plan. Under the NQDC Plan, participants have the right to defer a percentage of base salary as well as receive discretionary credits from the Company. The Company's discretionary credits vest over time. Any benefits distributed from the NQDC Plan plan are paid from the general assets of the Company. As the plan is unfunded, the balance reflected in the table below is a noncurrent liability included in benefit plan liabilities on the consolidated balance sheet.
2022 | 2021 | |||||||
Beginning deferred compensation balance | $ | 35,344 | $ | — | ||||
Employer contributions | 33,280 | 48,100 | ||||||
Participant contributions | — | — | ||||||
Earnings (loss) | (9,516 | ) | 2,297 | |||||
Distributions | — | (15,053 | ) | |||||
Ending deferred compensation balance | $ | 59,108 | $ | 35,344 | ||||
The Company sponsors a defined contribution plan (the “401k Plan”)401k Plan covering all eligible employees who elect to participate. Employees may contribute from 1% to 50% of their annual compensation to the 401k Plan, limited to a maximum annual amount as set periodically by the Internal Revenue Service.IRS. The Company matches 100% of the participant’s first 4% of contributions and 50% on the next 2% of contributions. Company matchingThe 401k Plan also provides for discretionary contributions were $361,702, $353,793 and $338,896 for 2017, 2016 and 2015, respectively.
Years Ended September 30 | ||||||||
2022 | 2021 | |||||||
Matching contribution | $ | 357,293 | $ | 383,340 | ||||
Discretionary contribution | 47,429 | 43,093 | ||||||
10. | |
COMMON STOCK OPTIONS |
The KESOP provides for the issuance of common stock options to officers and certain other full-time salaried employees to acquire shares of the Company’s common stock. As of September 30, 2017,2022, the number of shares available for future grants was 36,000.
ASC No. 718,Compensation-
As the Company's stock options are not traded on the open market, the fair value of each grant is estimated on the date of grant using the Black-Scholes option pricing model including the following assumptions:
| Years Ended September 30, | |||||
| 2017 | 2016 | 2015 | |||
| Expected volatility | 26.09% | 28.78% | 34.34% | ||
| Expected dividends | 3.81% | 3.99% | 4.11% | ||
| Expected exercise term (years) | 7.00 | 7.00 | 7.00 | ||
| Risk-free interest rate | 2.20% | 2.10% | 1.98% | ||
Years Ended September 30 | ||||||||
2022 | 2021 | |||||||
Expected volatility | 31.79 | % | 32.05 | % | ||||
Expected dividends | 2.77 | % | 2.75 | % | ||||
Expected exercise term (years) | 7 | 7 | ||||||
Risk-free interest rate | 2.89 | % | 1.24 | % | ||||
The underlying methods regarding each assumption are as follows:
Expected volatility
is based on the historicalExpected dividend rate
is based on historical dividend payout trends.Expected exercise term
is based on the average time historical option grants were outstanding before being exercised.Risk-free interest rate
is based on theForfeitures
are recognized when they occur.Stock option transactions under the Company's plans for the years ended September 30, 2017, 2016 and 2015 are summarized below. The information contained in the tables below have been restated to reflect the effect of the stock split:
| Number of Shares | Weighted- Average Exercise Price | Weighted- Average Remaining Contractual Terms (years) | Aggregate Intrinsic Value 1 | ||||||||||
| Options outstanding, September 30, 2014 | 57,000 | $ | 12.65 | 8.8 | $ | 34,840 | |||||||
| Options granted | 25,500 | 14.40 | |||||||||||
| Options exercised | (3,900 | ) | 12.66 | ||||||||||
| Options expired | — | — | |||||||||||
| Options forfeited | — | — | |||||||||||
| Options outstanding, September 30, 2015 | 78,600 | 13.22 | 8.3 | 43,086 | |||||||||
| Options granted | 24,000 | 14.15 | |||||||||||
| Options exercised | (3,300 | ) | 12.65 | ||||||||||
| Options expired | — | — | |||||||||||
| Options forfeited | (12,000 | ) | 13.20 | ||||||||||
| Options outstanding, September 30, 2016 | 87,300 | 13.50 | 7.8 | 200,211 | |||||||||
| Options granted | 25,500 | 16.37 | |||||||||||
| Options exercised | (11,225 | ) | 12.67 | ||||||||||
| Options expired | — | — | |||||||||||
| Options forfeited | — | — | |||||||||||
| Options outstanding, September 30, 2017 | 101,575 | $ | 14.31 | 7.6 | $ | 1,448,338 | |||||||
| Vested and exercisable at September 30, 2017 | 101,575 | $ | 14.31 | 7.6 | $ | 1,448,338 | |||||||
Number of Shares | Weighted- Average Exercise Price | Weighted- Average Remaining Contractual Terms (years) | Aggregate Intrinsic Value1 | |||||||||||||
Options outstanding, September 30, 2020 | 51,500 | $ | 18.34 | 6.4 | $ | 320,797 | ||||||||||
Options granted | 3,000 | 22.93 | ||||||||||||||
Options exercised | (9,250 | ) | 14.90 | |||||||||||||
Options expired | — | — | ||||||||||||||
Options forfeited | — | — | ||||||||||||||
Options outstanding, September 30, 2021 | 45,250 | $ | 19.34 | 6.0 | $ | 213,898 | ||||||||||
Options granted | 6,000 | 19.90 | ||||||||||||||
Options exercised | (8,750 | ) | 14.49 | |||||||||||||
Options expired | — | — | ||||||||||||||
Options forfeited | (8,000 | ) | 27.87 | |||||||||||||
Options outstanding, September 30, 2022 | 34,500 | $ | 18.69 | 5.7 | $ | 121,278 | ||||||||||
Vested and exercisable at September 30, 2022 | 28,500 | $ | 18.44 | 4.8 | $ | 114,318 | ||||||||||
1
Aggregate intrinsic value includes only those options where the exercise price is below the market price.Years Ended September 30 | ||||||||
2022 | 2021 | |||||||
Weighted-average grant date option fair value | $ | 5.39 | $ | 5.55 | ||||
Stock option expense | 16,330 | 11,100 | ||||||
Intrinsic value of options exercised | 58,944 | 70,297 | ||||||
Proceeds from exercise of stock options | 126,814 | 137,801 | ||||||
| Years Ended September 30, | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Weighted-average grant date option fair value | $ | 2.89 | $ | 2.69 | $ | 3.28 | |||||
| Stock option expense | 73,780 | 64,640 | 83,640 | ||||||||
| Intrinsic value of options exercised | 99,929 | 8,418 | 5,624 | ||||||||
| Proceeds from exercise of stock options | 142,241 | 41,762 | 49,366 | ||||||||
11. | |
OTHER STOCK PLANS |
Dividend Reinvestment and Stock Purchase Plan
The Company offers a Dividend Reinvestment and Stock PurchaseDRIP Plan (the “DRIP”) to shareholders of record for the reinvestment of dividends and the purchase of up to $40,000$100,000 per year in additional shares of common stock of the Company. Under the DRIP, the Company issued 36,446, 52,14634,290 and 12,64729,604 shares in 2017, 20162022 and 2015,2021, respectively. As of September 30, 2017,2022, the Company had 448,973298,429 shares of stock available for issuance under the DRIP.
Restricted Stock Plan for Outside Directors
The Board of Directors of the Company implemented the Restricted Stock Plan for Outside Directors (the “Plan”) effective January 27, RSPD in 1997. Under the Plan,RSPD, each director may elect annually to have up to 100% of his or her fees paid in shares of common stock ("Director Restricted Stock"); however, a minimum of 40% of the monthly retainer fee must be paid to each non-employee director of Resources was paid in shares of common stock (“Director Restricted Stock”).Stock until such time as the director has accumulated at least 10,000 shares. The number of shares of Director Restricted Stock awarded each month is determined based on the closing sales price of Resources' common stock on the NASDAQ Global Market on the first business day of the month. The Director Restricted Stock issued under the Plan vests only in the case of a participant's death, disability, retirement, or in the event of a change in control of Resources. The Director Restricted Stock may not be sold, transferred, assigned or pledged by the participant until the shares have vested under the terms of the Plan. The shares of Director Restricted Stock will be forfeited to Resources by a participant's voluntary resignation during his or her term on the Board or removal for cause as a director. Effective October 1, 2016, the Board of Directors amended the Plan to remove the requirement that directors take a minimum 40% of their retainer in Restricted Stock for those directors who owned at least 10,000 shares of Resources stock.
The Company assumes all directors will complete their term and there will be no forfeiture of the Director Restricted Stock. Since the inception of the Plan, RSPD, no director has forfeited any shares of Director Restricted Stock. The Company recognizes as compensation the market value of the Director Restricted Stock in the period it is issued.
The following table reflects the director compensation activity pursuant to the Plan:
| 2017 | 2016 | 2015 | ||||||||||||||||||
| Shares | Weighted-Average Fair Value on Date of Grant | Shares | Weighted-Average Fair Value on Date of Grant | Shares | Weighted-Average Fair Value on Date of Grant | |||||||||||||||
| Beginning of year balance | 107,023 | $ | 10.11 | 100,373 | $ | 9.80 | 94,267 | $ | 9.53 | |||||||||||
| Granted | 4,870 | 16.77 | 6,650 | 14.79 | 6,106 | 13.92 | ||||||||||||||
| Vested | — | — | — | — | — | — | ||||||||||||||
| Forfeited | — | — | — | — | — | — | ||||||||||||||
| End of year balance | 111,893 | $ | 10.56 | 107,023 | $ | 10.11 | 100,373 | $ | 9.80 | |||||||||||
2022 | 2021 | |||||||||||||||
Shares | Weighted-Average Fair Value on Date of Grant | Shares | Weighted-Average Fair Value on Date of Grant | |||||||||||||
Beginning of year balance | 110,444 | $ | 15.05 | 99,070 | $ | 14.06 | ||||||||||
Granted | 13,538 | 21.55 | 11,374 | 23.67 | ||||||||||||
Vested | (15,855 | ) | 12.33 | — | — | |||||||||||
Forfeited | — | — | — | — | ||||||||||||
End of year balance | 108,127 | $ | 16.27 | 110,444 | $ | 15.05 | ||||||||||
The fair market value of the Director Restricted Stock issued asincluded in compensation during fiscal 2017, 20162022 and 20152021 was $99,400, $98,334$291,767 and $85,000.$269,200, respectively. No Director Restricted Stock vested or was forfeited during fiscal 2017, 2016 and 2015.
As of September 30, 2017,2022, the Company had 85,23316,779 shares available for issuance under the Plan.
RGC Resources, Inc. Restricted Stock Plan
The Board of Directors of the Company implemented the RGC Resources, Inc. Restricted Stock Plan (the “Restricted Stock Plan”)RSPO in 2017 following approval as approved by the shareholders at the Company's annual meeting held on February 6, 2017.shareholders. Under the Restricted Stock Plan,RSPO, the Compensation Committee of the Board of Directors may grant shares of restrictedcommon stock ("Officer Restricted Stock") that vest over time to key employees and officers for the purpose of attracting and retaining those individuals essential to the operation and growth of the Company. The Restricted Stock PlanRSPO provides for certain restrictions and non-transferability requirements until minimum levels of ownership are obtained. Such restrictions may continue beyond the vesting period.
The Company assumes all officers will complete their requirements and there will be no forfeiture of the Officer Restricted Stock.
The following table reflects the officer compensation activity pursuant to the RSPO:
2022 | 2021 | |||||||||||||||
Shares | Weighted-Average Fair Value on Date of Grant | Shares | Weighted-Average Fair Value on Date of Grant | |||||||||||||
Beginning of year balance | 11,836 | $ | 25.17 | 6,815 | $ | 28.55 | ||||||||||
Granted | 26,897 | 23.19 | 16,656 | 24.21 | ||||||||||||
Vested | (16,194 | ) | 24.29 | (11,635 | ) | 25.77 | ||||||||||
Forfeited | — | — | — | — | ||||||||||||
End of year balance | 22,539 | $ | 23.44 | 11,836 | $ | 25.17 | ||||||||||
The fair market value of the Officer Restricted Stock Plan originally authorized 300,000included as compensation during fiscal 2022 and 2021 was $534,710 and $366,869, respectively. As of September 30, 2022, the Company had 367,983 shares to be available for issuance; however, following the three-for-two stock split on March 1, 2017, the total authorized shares increased to 450,000. As of September 30, 2017, no shares have been grantedissuance under the Restricted Stock Plan.
Stock Bonus Plan
Shares from the Stock Bonus Plan may also be issued to certain employees and management personnel in recognition of their performance and service. Under the Stock Bonus Plan, the Company issued 1,628, 2,813no shares in 2022 and 4,097 shares valued at $30,154, $39,819 and $59,332, respectively, in 2017, 2016 and 2015.2021. As of September 30, 20172022 the Company had 4,785 shares of stock available for issuance under the Stock Bonus Plan.
12. | |
COMMITMENTS AND CONTINGENCIES |
Long-Term Contracts
Due to the nature of the natural gas distribution business, the CompanyRoanoke Gas enters into agreements with both suppliers and pipelines to contract for natural gas commodity purchases, storage capacity and pipeline delivery capacity. The CompanyRoanoke Gas obtains most of its regulated natural gas supply through ana third party asset management contract betweencontract. Roanoke Gas and a third party asset manager. The Company utilizes an asset manager to optimize the use of its transportation, storage rights and gas supply inventories, which helps to ensure a secure and reliable source of natural gas. Under the current asset management contract, the CompanyRoanoke Gas has designated the asset manager to act as agent for the Company'sits storage capacity and all gas balances in storage. The CompanyRoanoke Gas retains ownership of gas in storage. Under provisions of this contract, the CompanyRoanoke Gas is obligated to purchase its winter storage requirements from the asset manager during the spring and summer injection periods at market price. The table below details the volumetric obligations as of September 30, 20172022 for the remainder of the contract period. The current asset management contract was renewed in September 2022 for a two year period which will expire in March 2018.
Natural Gas Contracts | ||||
Year | (In DTHs) | |||
2022-2023 | 2,081,134 | |||
2023-2024 | 2,071,061 | |||
2024-2025 | 295,866 | |||
Total | 4,448,061 | |||
In addition to the volumetric commitment above, the Company also has fixed price agreements to purchase approximately 2.1 million DTH, from October 2022 to March 2023, at prices ranging from $4.81 to $8.10 per DTH.
Roanoke Gas also has contracts for pipeline and storage capacity which extend for various periods. These capacity costs and related fees are valued at tariff rates in place as of September 30, 2017.2022. These rates may increase or decrease in the future based upon rate filings and rate orders granting a rate change to the pipeline or storage operator. Roanoke Gas expended approximately $28,496,000, $24,852,000$51,408,000 and $33,405,000$33,894,000 under the asset management, pipeline and storage contracts in fiscal years 2017, 20162022 and 2015,2021, respectively. The table below details the pipeline and storage capacity obligationscommitments as of September 30, 20172022 for the remainder of the contract period.
| Year | Pipeline and Storage Capacity | |||
| 2017-2018 | $ | 11,232,436 | ||
| 2018-2019 | 10,113,115 | |||
| 2019-2020 | 7,633,155 | |||
| 2020-2021 | 5,221,751 | |||
| 2021-2022 | 4,565,743 | |||
| Thereafter | 3,067,053 | |||
| Total | $ | 41,833,253 | ||
Pipeline and | ||||
Year | Storage Capacity | |||
2022 - 2023 | $ | 13,688,591 | ||
2023 - 2024 | 12,289,440 | |||
2024 - 2025 | 8,749,618 | |||
2025 - 2026 | 5,018,163 | |||
2026 - 2027 | 3,839,631 | |||
Thereafter | 581,542 | |||
Total | $ | 44,166,985 | ||
Roanoke Gas maintains franchise agreements granted by the local cities and towns served by the Company. Roanoke Gas renewed its franchise agreements with the City of Roanoke, the City of Salem and the Town of Vinton in 2016 for 20-year terms to expire in December 2035. Per these agreements, franchise fees increase at a rate of 3% annually. As of September 30, 2022, $2,063,500 in future obligations remain under the franchise agreements.
Other Contracts
The Company maintains other agreements in the ordinary course of business covering various lease, maintenance, equipment and service contracts. These agreements currently extend through December 2031 and are not material to the Company.
Legal
From time to time, the Company may become involved in litigation or claims arising out of its operations in the normal course of business. At the current time, the Company is not known to be a party to any legal proceedings that would be expected to have a materially adverse impact on its financial position, results of operations or cash flows.
Environmental Matters
Roanoke Gas and a previously owned gas subsidiary operated manufactured gas plants (MGPs)an MGP as a source of fuel for lighting and heating until the early 1950’s. A by-product of operating MGPsthe MGP was coal tar, and the potential exists for tar waste contaminants at the former plant sites.site. While the Company does not currently recognize any commitments or contingencies related to environmental costs, at either site, should the Company ever be required to remediate eitherthe site, it will pursue all prudent and reasonable means to recover any related costs, including the use of insurance claims and regulatory approval for rate case recognition of expenses associated with any work required.
13. | |
FAIR VALUE MEASUREMENTS |
The following table summarizes the Company’s financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements by level within the fair value hierarchy as defined in Note 1 as of September 30, 2017 2022 and 2016,2021, respectively:
Fair Value Measurements - September 30, 2022 | ||||||||||||||||
Quoted Prices in Active Markets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
Fair Value | Level 1 | Level 2 | Level 3 | |||||||||||||
Assets: | ||||||||||||||||
Interest rate swaps | $ | 4,798,467 | $ | — | $ | 4,798,467 | $ | — | ||||||||
Total | $ | 4,798,467 | $ | — | $ | 4,798,467 | $ | — | ||||||||
Liabilities: | ||||||||||||||||
Natural gas purchases | $ | 1,295,225 | $ | — | $ | 1,295,225 | $ | — | ||||||||
Total | $ | 1,295,225 | $ | — | $ | 1,295,225 | $ | — | ||||||||
Fair Value Measurements - September 30, 2021 | ||||||||||||||||
Quoted Prices in Active Markets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
Fair Value | Level 1 | Level 2 | Level 3 | |||||||||||||
Liabilities: | ||||||||||||||||
Natural gas purchases | $ | 2,728,935 | $ | — | $ | 2,728,935 | $ | — | ||||||||
Interest rate swaps | 1,196,083 | — | 1,196,083 | — | ||||||||||||
Total | $ | 3,925,018 | $ | — | $ | 3,925,018 | $ | — | ||||||||
The fair value of the interest rate swaps are determined by using the counterparty's proprietary models that include observable quoted market interest rates and interest rate futures as well as certain assumptions regarding past, present and future market conditions.
| Fair Value Measurements - September 30, 2017 | ||||||||||||||||
| Fair Value | Quoted Prices in Active Markets Level 1 | Significant Other Observable Inputs Level 2 | Significant Unobservable Inputs Level 3 | |||||||||||||
| Assets: | ||||||||||||||||
| Interest rate swaps | $ | 116,843 | $ | — | $ | 116,843 | $ | — | ||||||||
| Total | $ | 116,843 | $ | — | $ | 116,843 | $ | — | ||||||||
| Liabilities: | ||||||||||||||||
| Natural gas purchases | $ | 805,159 | $ | — | $ | 805,159 | $ | — | ||||||||
| Total | $ | 805,159 | $ | — | $ | 805,159 | $ | — | ||||||||
| Fair Value Measurements - September 30, 2016 | ||||||||||||||||
| Fair Value | Quoted Prices in Active Markets Level 1 | Significant Other Observable Inputs Level 2 | Significant Unobservable Inputs Level 3 | |||||||||||||
| Liabilities: | ||||||||||||||||
| Natural gas purchases | $ | 1,052,930 | $ | — | $ | 1,052,930 | $ | — | ||||||||
| Total | $ | 1,052,930 | $ | — | $ | 1,052,930 | $ | — | ||||||||
Under the asset management contract, a timing difference can exist between the payment for natural gas purchases and the actual receipt of such purchases. Payments are made based on a predetermined monthly volume with the price based on the weighted average first of the month index prices corresponding to the month of the scheduled payment. At September 30, 2017 2022 and 2016,2021, the Company had recorded in accounts payable the estimated fair value of the liability determinedbased on the corresponding first of month quoted index prices for which the liability was expected to be settled.
The Company’s nonfinancialnon-financial assets and liabilities that are measured at fair value on a nonrecurring basis consist of its asset retirement obligations. The asset retirement obligations are measured at fair value at initial recognition based on expected future cash flows to settle the obligation.
The carrying value of cash and cash equivalents, accounts receivable, borrowings under line-of-credit, accounts payable (with the exception of the timing difference under the asset management contract), customer credit balances and customer deposits is a reasonable estimate of fair value due to the shorter-term nature of these financial instruments. The following table summarizes the fair value of the Company’s financial assets and liabilities that are not adjusted to fair value in the consolidated financial statements as of September 30, 2017 2022 and 2016.
| Fair Value Measurements - September 30, 2017 | ||||||||||||||||
| Carrying Amount | Quoted Prices in Active Markets Level 1 | Significant Other Observable Inputs Level 2 | Significant Unobservable Inputs Level 3 | |||||||||||||
| Liabilities: | ||||||||||||||||
| Long-term debt | $ | 43,812,200 | $ | — | $ | — | $ | 45,689,238 | ||||||||
| Total | $ | 43,812,200 | $ | — | $ | — | $ | 45,689,238 | ||||||||
| Fair Value Measurements - September 30, 2016 | ||||||||||||||||
| Carrying Amount | Quoted Prices in Active Markets Level 1 | Significant Other Observable Inputs Level 2 | Significant Unobservable Inputs Level 3 | |||||||||||||
| Liabilities: | ||||||||||||||||
| Long-term debt | $ | 33,896,200 | $ | — | $ | — | $ | 36,163,523 | ||||||||
| Total | $ | 33,896,200 | $ | — | $ | — | $ | 36,163,523 | ||||||||
Fair Value Measurements - September 30, 2022 | ||||||||||||||||
Carrying | Quoted Prices in Active Markets | Significant Other Observable Inputs | Significant Unobservable Inputs | |||||||||||||
Amount | Level 1 | Level 2 | Level 3 | |||||||||||||
Liabilities: | ||||||||||||||||
Current maturities of long-term debt | $ | 1,300,000 | $ | — | $ | — | $ | 1,300,000 | ||||||||
Notes payable | 135,971,200 | — | — | 130,266,252 | ||||||||||||
Total | $ | 137,271,200 | $ | — | $ | — | $ | 131,566,252 | ||||||||
Fair Value Measurements - September 30, 2021 | ||||||||||||||||
Carrying | Quoted Prices in Active Markets | Significant Other Observable Inputs | Significant Unobservable Inputs | |||||||||||||
Amount | Level 1 | Level 2 | Level 3 | |||||||||||||
Liabilities: | ||||||||||||||||
Current maturities of long-term debt | $ | 7,000,000 | $ | — | $ | — | $ | 7,000,000 | ||||||||
Notes payable | 116,110,200 | — | — | 124,691,896 | ||||||||||||
Total | $ | 123,110,200 | $ | — | $ | — | $ | 131,691,896 | ||||||||
The fair value of long-term debt for Roanoke Gas is estimated by discounting the future cash flows of the fixed rate debt based on the underlying 20-year20-year Treasury rate or other Treasury instrument with a corresponding maturity period and estimated credit spread extrapolated based on market conditions since the issuance of the debt. A 64 basis point increase in the 20-year Treasury in fiscal 2017 partially offset by a reduction in the assumed credit spreads accounted for the smaller differential between the fair value and the carrying amount of the notes payable at the end of the year. The fair value for the RGC Midstream debt is estimated by discounting the estimated credit spread extrapolated based on market conditions.
ASC 825, –
14. | |
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) |
Quarterly financial data for the years ended September 30, 2017 2022 and 20162021 is summarized as follows:
First | Second | Third | Fourth | |||||||||||||
2022 | Quarter | Quarter | Quarter | Quarter | ||||||||||||
Operating revenues | $ | 23,263,080 | $ | 29,529,683 | $ | 17,259,899 | $ | 14,112,560 | ||||||||
Operating income | $ | 5,378,423 | $ | 7,443,388 | $ | 1,640,172 | $ | 454,692 | ||||||||
Net income (loss) | $ | 3,584,529 | $ | (24,494,429 | ) | $ | 592,527 | $ | (11,415,229 | ) | ||||||
Earnings (loss) per share of common stock: | ||||||||||||||||
Basic | $ | 0.43 | $ | (2.89 | ) | $ | 0.06 | $ | (1.16 | ) | ||||||
Diluted | $ | 0.43 | $ | (2.89 | ) | $ | 0.06 | $ | (1.16 | ) | ||||||
First | Second | Third | Fourth | |||||||||||||
2021 | Quarter | Quarter | Quarter | Quarter | ||||||||||||
Operating revenues | $ | 19,517,017 | $ | 28,253,662 | $ | 14,048,846 | $ | 13,355,254 | ||||||||
Operating income | $ | 5,581,387 | $ | 7,099,426 | $ | 1,542,333 | $ | 555,163 | ||||||||
Net income | $ | 4,723,263 | $ | 4,767,478 | $ | 610,840 | $ | 481 | ||||||||
Earnings per share of common stock: | ||||||||||||||||
Basic | $ | 0.58 | $ | 0.58 | $ | 0.07 | $ | — | ||||||||
Diluted | $ | 0.58 | $ | 0.58 | $ | 0.07 | $ | — | ||||||||
| 2017 | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||||
| Operating revenues | $ | 18,788,585 | $ | 21,900,013 | $ | 11,435,824 | $ | 10,172,448 | ||||||||
| Gross margin | $ | 9,390,905 | $ | 10,829,730 | $ | 6,634,402 | $ | 5,954,120 | ||||||||
| Operating income | $ | 3,982,275 | $ | 5,589,207 | $ | 1,328,207 | $ | 766,620 | ||||||||
| Net income | $ | 2,232,218 | $ | 3,225,199 | $ | 615,562 | $ | 159,886 | ||||||||
| Earnings per share of common stock: | ||||||||||||||||
| Basic | $ | 0.31 | $ | 0.45 | $ | 0.09 | $ | 0.02 | ||||||||
| Diluted | $ | 0.31 | $ | 0.45 | $ | 0.08 | $ | 0.02 | ||||||||
| 2016 | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||||
| Operating revenues | $ | 16,010,056 | $ | 21,777,773 | $ | 11,295,197 | $ | 9,980,265 | ||||||||
| Gross margin | $ | 8,738,116 | $ | 10,649,269 | $ | 6,312,340 | $ | 5,865,189 | ||||||||
| Operating income | $ | 3,498,052 | $ | 5,444,314 | $ | 1,453,350 | $ | 816,376 | ||||||||
| Net income | $ | 1,922,790 | $ | 3,111,447 | $ | 627,068 | $ | 145,561 | ||||||||
| Earnings per share of common stock: | ||||||||||||||||
| Basic | $ | 0.27 | $ | 0.44 | $ | 0.09 | $ | 0.02 | ||||||||
| Diluted | $ | 0.27 | $ | 0.44 | $ | 0.09 | $ | 0.02 | ||||||||
15. | |
SUBSEQUENT EVENTS |
On October 2, 2017, Roanoke Gas entered into two 10-year unsecured notes with Prudential Investment ManagementNovember 1, 2022, the Company determined, as a result of its quarterly analysis of the equity investment in the total principal amount of $8,000,000. The notes have an annual interest rate of 3.58%. The proceeds fromLLC by its wholly owned affiliate Midstream, a material impairment likely existed due to increasing uncertainty concerning the note will be used to convert a portionultimate completion of the Company's line-of-credit balance into longer-term financing.
The Company has evaluated subsequent events through the date the financial statements were issued. There were no other items not otherwise disclosed which would have materially impacted the Company’s consolidated financial statements.
None.
Item 9A.Controls and Procedures.
The Company maintains disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) that are designed to be effective in providing reasonable assurance that information required to be disclosed in reports under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission (the “SEC”),SEC, and that such information is accumulated and communicated to management to allow for timely decisions regarding required disclosure.
As of September 30, 2017,2022, the Company completed an evaluation, under the supervision and with the participation of management, including the chief executive officer and the chief financial officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures. Based upon that evaluation, the chief executive officer and chief financial officer concluded that the Company’s disclosure controls and procedures were effective at the reasonable assurance level as of September 30, 2017.
Management routinely reviews the Company’s internal control over financial reporting and makes changes, as necessary, to enhance the effectiveness of the internal controls over financial reporting. There were no changes in the internal controls over financial reporting during the fourth quarter of the fiscal year covered by this report that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) under the Securities and Exchange Act of 1934). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation and fair presentation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of AmericaGAAP and include those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles,GAAP, and that receipts and expenditures are being made only in accordance with authorizations of the management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations, any system of internal control over financial reporting, no matter how well designed, may not prevent or detect misstatements due to the possibility that a control can be circumvented or overridden or that misstatements due to error or fraud may occur that are not detected. Projections of the effectiveness to future periods are subject to the risk that the internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures included in such controls may deteriorate. The Company’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.
The Company has conducted an evaluation of the design and effectiveness of the Company’s system of internal control over financial reporting as of September 30, 2017,2022, based on the framework set forth in ”
None
|
For information with respect to the executive officers of the registrant, see “Executive Officers" section in the Proxy Statement for the For information regarding the process for identifying and evaluating candidates to be nominated as directors, see "Director Nominations" in the Proxy Statement for the Information with respect to compliance with Section 16(a) of the Exchange Act, which is set forth under the caption The Company has adopted a Code of Ethics applicable to all of its officers, directors and employees. The Company has posted the text of its Code of Ethics on its website at The information set forth under "Compensation of Directors", "Compensation Discussion and Analysis" and "Report of the Compensation Committee" in the Proxy Statement for the For information pertaining to securities authorized for issuance under equity compensation plans, see Part II, Item 5 above. The information pertaining to shareholders beneficially owning more than five percent of the registrant’s common stock and the security ownership of management, which is set forth under the caption “Security Ownership of Certain Beneficial Owners and Management" in the Proxy Statement for the The information pertaining to director independence is set forth under the caption “Board of Directors and Committees of the Board of Directors” and pertaining to transactions with related persons is set forth under the caption "Transactions with Related Persons" in the Proxy Statement for the The information set forth under the caption "Report of the Audit Committee" in the Proxy Statement for the Item 15.Exhibits and Financial Statement Schedules. (a) List of documents filed as part of this report: 1. Financial statements filed as part of this report: All financial statements of the registrant as set forth under Item 8 of this Report on Form 10-K. 2. Financial statement schedules filed as part of this report: All information is inapplicable or presented in the consolidated financial statements or related notes thereto. 3. Exhibits. 1 (a) 3 (a) 3 (b) 4 (a) 4 (b) 4 (c) 10 (a) P Firm Transportation Agreement between East Tennessee Natural Gas Company and Roanoke Gas Company dated November 1, 1993 (incorporated herein by reference to Exhibit 10(a) of the Annual Report on Form 10-K for the fiscal year ended September 30, 1994 (SEC file number reference 0-367)) 10 (b) 10 (c) 10 (d) 10 (e) 10 (f) 10 (h) 10 (i) P Gas Transportation Agreement, for use under IT rate schedule, between Tennessee Gas Pipeline Company and Roanoke Gas Company dated September 1, 1993 (incorporated herein by reference to Exhibit 10(l) of the Annual Report on Form 10-K for the fiscal year ended September 30, 1994 (SEC file number reference 0-367)) 10 (j) 10 (v) 10 10 10 (y) 10 (a)(a) P Certificate of Public Convenience and Necessity for Bedford County dated February 21, 1966 (incorporated herein by reference to Exhibit 10(o) of Registration Statement No. 33-36605, on Form S-2, filed with the Commission on August 29, 1990, and amended by Amendment No. 1, filed with the Commission on September 19, 1990) 10 P Certificate of Public Convenience and Necessity for Roanoke County dated October 19, 1965 (incorporated herein by reference to Exhibit 10(p) of Registration Statement No. 33-36605, on Form S-2, filed with the Commission on August 29, 1990, and amended by Amendment No. 1, filed with the Commission on September 19, 10 P Certificate of Public Convenience and Necessity for Botetourt County dated August 30, 1966 (incorporated herein by reference to Exhibit 10(q) of Registration Statement No. 33-36605, on Form S-2, filed with the Commission on August 29, 1990, and amended by Amendment No. 1, filed with the Commission on September 19, 10 (d)(d) P Certificate of Public Convenience and Necessity for Montgomery County dated July 8, 1985 (incorporated herein by reference to Exhibit 10(r) of Registration Statement No. 33-36605, on Form S-2, filed with the Commission on August 29, 1990, and amended by Amendment No. 1, filed with the Commission on September 19, 10 P Resolution of the Council for the Town of Fincastle, Virginia dated June 8, 1970 (incorporated herein by reference to Exhibit 10(f) of Registration Statement No. 33-11383, on Form S-4, filed with the Commission on January 16, 10 P Resolution of the Council for the Town of Troutville, Virginia dated November 4, 1968 (incorporated herein by reference to Exhibit 10(g) of Registration Statement No. 33-11383, on Form S-4, filed with the Commission on January 16, 10 10 (h)(h) 10 10 10 (k)(k) 10 10 10 10 10 10 10 (r)(r) 10 (t)(t) 10 10 10 (w)(w) 10 (x)(x) 10 (y)(y) 10 (c)(c)(c) 10 10 10 10 10 10 10 (j)(j)(j) 10 (k)(k)(k) 10 (l)(l)(l) 10 (n)(n)(n) 10 10 10 10 10 (s)(s)(s) 10 10 10 10 (w)(w)(w) 10 (x)(x)(x) 10 (y)(y)(y) 10 (z)(z)(z) 10 (a)(a)(a)(a) 10 (b)(b)(b)(b) 10 (c)(c)(c)(c) 10 (d)(d)(d)(d) 10 (e)(e)(e)(e) 10 (x)(x)(x)(x) 13 14 Code of Ethics (incorporated herein by reference to Exhibit 14 on Form 10-Q as filed August 9, 2022) 21 23 31.1 31.2 32.1 * 32.2 * * These certifications are being furnished solely to accompany this annual report pursuant to 18 U.S.C. Section 1350, and are not being filed for purposes of Section 18 of the Securities Exchange Act of 1934 and are not to be incorporated by reference into any filing of the registrant, whether made before or after the date hereof, regardless of any general incorporation language in such filing. ** Confidential treatment has been granted with respect to portions of this exhibit, indicated by asterisks, which has been filed separately with the Securities and Exchange Commission. P These original exhibits were filed with the SEC in paper form and therefore are not hyper-linked to the original filing. Not applicable. Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Annual Report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized. RGC RESOURCES, INC. By: /S/ JASON A. FIELD December 2, 2022 Jason A. Field Date Vice President, CFO and Treasurer (Principal Financial Officer) Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report on Form 10-K has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. /S/ PAUL W. NESTER President and Chief Executive Officer, Director Paul W. Nester Date (Principal /S/ JASON A. FIELD Vice President, CFO and Jason A. Field Date (Principal Financial Officer) /S/ JOHN B. WILLIAMSON, III Chairman of the John B. Williamson, III Date /S/ NANCY H. AGEE Director Nancy H. Agee Date /S/ JACQUELINE L. ARCHER Director Jacqueline L. Archer Date /S/ ABNEY S. BOXLEY, III Director Abney S. Boxley, III Date /S/ T. JOE CRAWFORD Director T. Joe Crawford Date /S/ MARYELLEN F. GOODLATTE Director Maryellen F. Goodlatte Date /S/ ROBERT B. JOHNSTON /S/ J. ALLEN LAYMAN Director J. Allen Layman Date /S/ ELIZABETH A. MCCLANAHAN Director Elizabeth A. McClanahan DateItem 9B.Other Information.NoneItem 10.Directors, Executive Officers and Corporate Governance.20182023 Annual Meeting of Shareholders of Resources incorporated herein by reference. For information with respect to the Company’s directors and nominees and the Company’s Audit Committee, see Proposal 1 “Election of Directors of Resources” and “Report of the Audit Committee”, respectively, in the Proxy Statement for the 20182023 Annual Meeting of Shareholders of Resources, which information is incorporated herein by reference. In addition, the Board of Directors has determined that Abney S. Boxley, III George W. Logan and Raymond D. Smoot, Jr.Jacqueline L. Archer are audit committee financial experts under applicable SEC rules.20182023 Annual Meeting of Shareholders of Resources, which is incorporated herein by reference."Section 16 (a) Beneficial Ownership Reporting Compliance""Delinquent Section 16(a) Reports" in the Proxy Statement for the 20182023 Annual Meeting of Shareholders of Resources, is incorporated herein by reference. Corporate Governance and Nominating Committees of the Board of Directors. These documents may also be found on the Company’s website at www.rgcresources.com.Item 11.Executive Compensation.20182023 Annual Meeting of Shareholders of Resources is incorporated herein by reference.Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.20182023 Annual Meeting of Shareholders of Resources, is incorporated herein by reference.Item 13.Certain Relationships and Related Transactions, and Director Independence.20182023 Annual Meeting of Shareholders of Resources, which information is incorporated herein by reference.Item 14.Principal Accounting Fees and Services.20182023 Annual Meeting of Shareholders of Resources is incorporated herein by reference.PART IVItem 15.Exhibits and Financial Statement Schedules.(a)List of documents filed as part of this report:1.Financial statements filed as part of this report:2.Financial statement schedules filed as part of this report:3.ExhibitsMarch 5, 2020) 10 (f) 10 (o) 10 (i)(i)13212331.131.232.1*32.2*101The following documents from the Registrant’s Annual Report on Form 10-K for the years ended September 30, 2017, 2016 and 2015, formatted in XBRL (eXtensible Business Reporting Language); Consolidated Balance Sheets at September 30, 2017 and 2016, (ii) Consolidated Statements of Income for the years ended September 30, 2017, 2016 and 2015, (iii) Consolidated Statements of Comprehensive Income for the years ended September 30, 2017, 2016 and 2015, (iv) Consolidated Statements of Stockholders’ Equity for the years ended September 30, 2017, 2016 and 2015, (v) Consolidated Statements of Cash Flows for the years ended September 30, 2017, 2016 and 2015, and (vi) Notes to Consolidated Financial Statements.*These certifications are being furnished solely to accompany this annual report pursuant to 18 U.S.C. Section 1350, and are not being filed for purposes of Section 18 of the Securities Exchange Act of 1934 and are not to be incorporated by reference into any filing of the registrant, whether made before or after the date hereof, regardless of any general incorporation language in such filing.Item 16.Form 10-K Summary.Not applicable.SIGNATURESPursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Annual Report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized.RGC RESOURCES, INC.By:/S/ PAUL W. NESTER December 8, 2017Paul W. NesterDateVice President, Secretary, Treasurer and CFO(principal accounting and financial officer)Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report on Form 10-K has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated./S/ JOHN S. D'ORAZIO December 8, 2017President and Chief Executive Officer, DirectorJohn S. D'OrazioDate/S/ PAUL W. NESTER December 8, 2017Vice President, Treasurer and CFO(principal accounting and financial officer)Paul W. NesterDate/S/ JOHN B. WILLIAMSON, III December 8, 2017Chairman of the Board and DirectorJohn B. Williamson, IIIDate/S/ NANCY H. AGEE December 8, 2017DirectorNancy H. AgeeDate/S/ ABNEY S. BOXLEY, III December 8, 2017DirectorAbney S. Boxley, IIIDate/S/ MARYELLEN F. GOODLATTE December 8, 2017DirectorMaryellen F. GoodlatteDate/S/ J. ALLEN LAYMAN December 8, 2017DirectorJ. Allen LaymanDate/S/ GEORGE W. LOGAN December 8, 2017DirectorGeorge W. LoganDate/S/ S. FRANK SMITH December 8, 2017DirectorS. Frank SmithDate/S/ RAYMOND D. SMOOT, JR. December 8, 2017DirectorRaymond D. Smoot, Jr.DateEXHIBIT INDEXExhibit No.Description3 (a) 3 4 (a)4 (b) 10 (f) 10 (g) P P 10 (t) (u)(w) (v)(x) 10 (w)(z)PAmendment dated November 29, 2021 to Gas Transportation Agreement originally dated December 1, 1993 between Tennessee Gas Pipeline and Roanoke Gas Company (incorporated herein by reference to Exhibit 10(s)(s)(s)(s) on Form 10-K for the year ended September 30, 2021) (x)(b)(b)1990)1990 (SEC file number reference 0-367)) (y)(c)(c)1990)1990 (SEC file number reference 0-367)) 10 (z)P1990)1990 (SEC file number reference 0-367)) (a)(a)(e)(e)Certificate of Public Convenience and Necessity for Franklin County dated September 8, 1964 (incorporated herein by reference to Exhibit 10(t) of Registration Statement No. 33-36605, on Form S-2, filed with the Commission on August 29, 1990, and amended by Amendment No. 1, filed with the Commission on September 19, 1990)10 (b)(b)P1987)1987 (SEC file number reference 0-367)) (c)(c)(f)(f)1987)1987 (SEC file number reference 0-367)) (d)(d)(g)(g) (e)(e)(i)(i) (f)(f)(j)(j) 10 (g)(g) (h)(h)(l)(l) (i)(i)(m)(m) (j)(j)(n)(n) (k)(k)(o)(o) (l)(l)(p)(p) (m)(m)(q)(q) 10 (n)(n)(s)(s) (o)(o)(u)(u) 10 (p)(p) (q)(q)(v)(v) 10 (r)(r)(z)(z) 10 (a)(a)(a) Sixth Amendment to Credit Agreement by and between Roanoke Gas Company and Wells Fargo Bank, N.A., including Guarantor's Consent and Reaffirmation, dated as of August 20, 2021 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed August 26, 2021) 10 (b)(b)(b) Seventh Amendment to Credit Agreement by and between Roanoke Gas Company and Wells Fargo Bank, N.A. dated March 31, 2022 (incorporated herein by reference to Exhibit 10.2 on Form 8-K as filed April 1, 2022) (s)(s)(d)(d)(d) 10 (t)(t) (u)(u)(e)(e)(e) (v)(v)(f)(f)(f) (w)(w)(g)(g)(g) (x)(x)(h)(h)(h) (y)(y)(i)(i)(i) 10 (z)(z)10 (a)(a)(a) 10 (b)(b)(b)(m)(m)(m) (c)(c)(c)(o)(o)(o) (d)(d)(d)(p)(p)(p) (e)(e)(e)(q)(q)(q) 10 (f)(f)(f)10 (g)(g)(g)10 (h)(h)(h)10 (i)(i)(i) (j)(j)(j)(r)(r)(r) (k)(k)(k)(t)(t)(t) (l)(l)(l)(u)(u)(u) (m)(m)(m)(v)(v)(v)10 (v)(v)(v)(v) Swap Agreement by and between RGC Midstream, LLC and Atlantic Union Bank, executed on November 1, 2021 (incorporated herein by reference to Exhibit 10.3 on Form 8-K as filed November 4, 2021) 10 (w)(w)(w)(w) 32.1*101.INS 101.SCH Inline XBRL Taxonomy Extension Schema Document 101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document 101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document 101.LAB Inline XBRL Taxonomy Extension Label Linkbase Document 101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document 104 Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101) Section 1350 Certification of Principal Executive OfficerItem 16.Form 10-K Summary. 32.2* Financial OfficerExecutive Officer) 101 The following documents from the Registrant’s Annual Report on Form 10-K for the years ended September 30, 2017, 2016December 2, 20222015, formatted in XBRL (eXtensible Business Reporting Language); Consolidated Balance Sheets at September 30, 2017 and 2016, (ii) Consolidated Statements of Income for the years ended September 30, 2017, 2016 and 2015, (iii) Consolidated Statements of Comprehensive Income for the years ended September 30, 2017. 2016 and 2015, (iv) Consolidated Statements of Stockholders’ Equity for the years ended September 30, 2017, 2016 and 2015, (v) Consolidated Statements of Cash Flows for the years ended September 30, 2017, 2016 and 2015, and (vi) Notes to Consolidated Financial Statements.Treasurer *These certifications are being furnished solely to accompany this annual report pursuant to 18 U.S.C. Section 1350, and are not being filed for purposes of Section 18December 2, 2022 Securities Exchange Act of 1934Board and are not to be incorporated by reference into any filing of the registrant, whether made before or after the date hereof, regardless of any general incorporation language in such filing.Director **Confidential treatment has been granted with respect to portions of this exhibit, indicated by asterisks, which has been filed separately with the Securities and Exchange Commission.PThese original exhibits were filed with the SEC in paper form and therefore are not hyper-linked to the original filing.December 2, 2022 December 2, 2022 December 2, 2022 December 2, 2022 December 2, 2022 December 2, 2022 Director Robert B. Johnston Date December 2, 2022 December 2, 2022